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

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

l L A N D & L E A S I N G

Vol. 23, No. 35 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of September 2, 2018 • $2.50

page2

Smith Bay deferred again, Nutrien still working to getgas to re-open Nikiski plant

RUMOR HAS IT CAELUS ENERGY

ALASKA will use part of the funds it

receives from Eni for its eastern North Slope

acreage (see page 1 story in this issue) to

either test its two Tulimaniq wildcat wells in

Smith Bay off the coast of the National

Petroleum Reserve-Alaska or do more

appraisal drilling at the prospect. An explo-

ration program was planned for early 2017

and again in early 2018, but both were deferred by the local

subsidiary of the Texas independent.

But the rumors are wrong, Pat Foley, senior vice president

IGU gets Houston LNG proposalfrom Knik, Siemens for new plant

On Aug. 21 Knik Tribe and industrial manufacturing com-

pany Siemens presented to the board of the Interior Gas

Utility a proposal for the construction of a liquefied natural

gas plant near Houston, next to a spur of the Alaska Railroad.

LNG would be transported to Fairbanks by rail in support of

an expanded supply of natural gas for the city and its sur-

rounds. The plant would be built on Native land zoned for

industrial development and owned by Knikatnu, the Native

village corporation for Knik and Wasilla.

The proposal comes as an alternative to expanding the

existing Titan LNG plant near Point Mackenzie. The increased

LNG supply is planned as part of the Interior Energy Project,

Results from Doyon/CIRI TotchaketNenana basin well not commercial

The Totchaket No. 1 exploration well, drilled in the Nenana

basin this summer by Doyon Ltd. and Cook Inlet Region Inc,

encountered multiple gas shows but did not find commercial

oil or gas, CIRI has reported. CIRI said that, based on drilling

results conducted so far in the basin, it continues to view the

basin as holding considerable resources.

Drilling of the Totchaket well, on the east side of the

Tanana River, about 20 miles north of the town of Nenana,

began on June 6 and ended on July 5. The well has since been

plugged and abandoned. According to data published by the

Alaska Oil and Gas Conservation Commission, the well was

drilled to a vertical depth of 11,225 feet.

Oil Search plans appraisal wellsat Pikka unit this winter season

Australia-based Oil Search Ltd. said in its Aug. 21 first half

results call with analysts that it plans to drill two appraisal wells

in 2018-19 at the Pikka unit it operates on Alaska’s North Slope.

Petroleum News has previously reported that the company plans

to use two drilling rigs for work this winter, an early indication of

plans to drill two wells.

Peter Botten, Oil Search managing director, reviewed the

company’s progress in Alaska since it acquired interests at Pikka,

Horseshoe and elsewhere on the North Slope from Armstrong

Energy last year. He discussed four stages of planned growth in

Alaska: development of the Nanushuk in the Pikka unit;

Nanushuk expansion, south into Horseshoe; exploration with a

focus on tie-back opportunities; and new business, including

see INSIDER page 10

see LNG PROPOSAL page 11

see WELL RESULTS page 10

see OIL SEARCH page 8

Rig contracted for Winx prospect2019 drilling by Captivate Energy

Eni buys Caelus blocksItalian major confirms acquisition of 350,000 acres on eastern North Slope

By KAY CASHMANPetroleum News

As reported in Oil Patch Insider in Petroleum

News’ Aug. 19 issue, Eni has acquired Caelus

Alaska’s eastern North Slope acreage, which con-

sists of 350,000 onshore acres between the

Prudhoe Bay and Point Thomson units (see accom-

panying map).

At that time a formal announcement had not

been made, but the Italian major confirmed the

purchase of the 124 state oil and gas leases in an

Aug. 29 press release.

Eni previously held some 35,120 acres on the

North Slope, bringing its new total to more than

385,000 acres.

Eni said the eastern exploration acreage "is con-

sidered a prime area with high potential and multi-

ple proven plays.” The company plans to “apply its

business model and experience,” involving “fast-

track exploration” and “a short time to market” for

the “potential new discoveries.”

A price was not disclosed. Eni also said the

EIS is publishedBOEM favors Hilcorp’s proposal to develop Liberty from offshore island

By ALAN BAILEYPetroleum News

The federal Bureau of Ocean Energy

Management has issued a final

Environmental Impact Statement for Hilcorp

Alaska’s planned Liberty oil field development in

the Beaufort Sea. The agency has confirmed a pre-

ferred alternative accepting Hilcorp’s proposal to

develop the field from a small gravel island in 19

feet of water about five miles offshore, and the lay-

ing of a buried subsea pipe-in-pipe pipeline to

carry crude oil to shore. The pipeline would con-

nect with the existing Badami pipeline for trans-

porting the Liberty oil to the trans-Alaska pipeline.

BOEM says that it anticipates the EIS being

published in the Federal Register on Aug. 31, with

a record of decision for the document being issued

30 days or more later.

Construction scheduleHilcorp has previously said that it hopes to start

building the 9.3-acre gravel island in late 2019,

Alberta now 17-0Notley elated by Supreme Court verdict against attempt to block Trans Mountain

By GARY PARKFor Petroleum News

The Alberta government is “batting a

thousand” in its legal defense of the

Trans Mountain pipeline project after

notching its 17th straight court victory,

the province’s Premier Rachel Notley

declared when the Supreme Court of

Canada rejected an appeal against expan-

sion of the line from Alberta to the

Pacific Coast.

“When the British Columbia government tried

to overstep its legal and constitutional authority,

we took bold action (threatening to cut off ship-

ments of Alberta crude to B.C.) — and they backed

down,” she said in a social media post.

“When the City of Burnaby tried to

block the Trans Mountain pipeline in

court, we intervened — and we won in

court.”

The Burnaby appeal of the project

approval by Canada’s National Energy

Board was one of the final court chal-

lenges being waged by British Columbia

and First Nations against the Alberta and

federal governments.

Burnaby asked Canada’s highest court

to overturn a lower court decision that allowed

pipeline owner Kinder Morgan to bypass local

bylaws during construction of the pipeline expan-

sion.

The court also ordered Burnaby to pay all of the

see ENI ACQUISITION page 12

see LIBERTY EIS page 9

see COURT VERDICT page 8

To the west of Prudhoe Bay, Eni owns andoperates the Nikaitchuq oil field and is aminority owner in the adjacent Caelus-

operated Oooguruk oil field, with a totalnet production of approximately 20,000

barrels of oil equivalent a day.

Shell Oil Co. discovered oil in the area ofthe Liberty field between 1982 and 1987,through the drilling of four wells into the

Kekiktuk formation from two artificialgravel islands.

RACHEL NOTLEY

2 PETROLEUM NEWS • WEEK OF SEPTEMBER 2, 2018

GOVERNMENT

PIPELINES & DOWNSTREAM

EXPLORATION & PRODUCTION

FINANCE & ECONOMY4 Enbridge tops up Spectra offer by 10%

2 Nordic-Calista rig contracted for ’19 well

4 State OKs Seaview exploration plan

5 A pause on tighter efficiency standards

DOT, EPA propose to freeze fuel efficiency standards for lightvehicles at 2020 levels for model years 2021 through 2026

Eni buys Caelus blocksItalian major confirms acquisition of 350,000 North Slope acres

EIS is publishedBOEM favors Hilcorp plan to develop Liberty from offshore island

Alberta now 17-0Notley elated by court verdict against attempt to block Trans Mtn.

ON THE COVER

Oil Patch Insider: Smith Bay deferred again,Nutrien working to get gas to re-open Nikiski plant

IGU gets Houston LNG proposalfrom Knik, Siemens for new plantResults from Doyon/CIRI TotchaketNenana basin well not commercialOil search plans appraisal wellsat Pikka unit this winter season

Petroleum News Alaska’s source for oil and gas newscontents

Keeping youcovered

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

Nordic-Calista rig contracted for ’19 wellBy KRISTEN NELSON

Petroleum News

88 Energy said Aug. 29 that its wholly owned subsidiary

Captivate Energy Alaska has contracted the Nordic-

Calista Services rig 3 to drill the Winx prospect.

Winx is on a block of four Great Bear Petroleum Leases

in which 88 Energy Ltd., Otto Energy Ltd. and Red Emperor

Ltd. acquired a collective 90 percent interest earlier in the

year. The lease terms, set to expire April 30, were extended

by the Division of Oil and Gas to April 30, 3021, contingent

on the drilling of an exploration well by May 30, 2019.

The 88 Energy consortium said when the lease acquisi-

tion and extension were announced that they would meet

that drilling commitment and said they would target the

Nanushuk play. The block on which the Winx prospect lies

is east of discovery wells at Horseshoe and west of

Meltwater.

88 Energy said at that time that Otto Energy had used

seismic data acquired from the division to identify a

prospect at a depth of some 5,000 feet in the Nanushuk.

In its Aug. 29 statement 88 Energy said the Winx 1 well

will test a 3-D seismically defined oil prospect in the

Nanushuk play fairway “comprising multiple stacked objec-

tives with a gross mean unrisked prospective resource” of

400 million barrels. The company rated the geological

chance of success at 25-30 percent.

Nordic-Calista Services rig 3 is a single module, self-pro-

pelled drilling rig, capable of drilling to depths of 12,000-

14,500 feet, 88 Energy said, and has previously been used

for grassroots drilling, exploration, sidetracks ad workovers

on the North Slope.

Western Block88 Energy said it is earning a 36 percent working interest

in the four leases in the western block, totaling 22,171 acres,

with its consortium partners Otto Energy and Red Emperor

Resources, with Otto eventually having a 22.5 percent inter-

est and Red Emperor 31.5 percent.

All three companies are based in Australia.

The companies have posted a $3 million performance

bond to the state and will fund 100 percent of the costs of the

well. The bond was a requirement of the state to extend the

term of the leases, along with the requirement to drill a well.

88 Energy has been investigating the potential for source

rock development on leases straddling the Dalton Highway,

and is also investigating conventional prospects on its

acreage. Project Icewine was 88 Energy’s first North Slope

venture, with a gross acreage position of some 475,000

acres, 301,000 acres net to 88 Energy. Icewine 1 has been

drilled and evaluated. Drilling at Icewine 2, an appraisal

well, concluded in 2017, with production testing at that well

concluded in June.

These wells targeted the HRZ.

The company said conventional prospects have been

identified in recently acquired 2-D and 3-D seismic across

project acreage.

88 Energy also has 100 percent working interest via a

subsidiary in Yukon Gold leases acquired earlier this year,

some 14,194 acres. The leases contain the Yukon Gold 1, a

historic discovery well. The company said 3-D seismic was

acquired in early 2018 to assist with evaluation of the

Yukon Gold acreage. l

6 Seawall would protect homes, oil industry

7 Governor’s race may hinge on PFD checks

5 Judge rules developer can’t sue Earth First

7 Judge confirms city’s right in lawsuit

PETROLEUM NEWS • WEEK OF SEPTEMBER 2, 2018 3

Rig Owner/Rig Type Rig No. Rig Location/Activity Operator or Status

Alaska Rig StatusNorth Slope - Onshore

Doyon DrillingDreco 1250 UE 14 (SCR/TD) Milne Point, MPLU-14 Hilcorp Dreco 1000 UE 16 (SCR/TD) Standby Dreco D2000 Uebd 19 (SCR/TD) GMTU, MT6-08 ConocoPhillipsAC Mobile 25 StandbyOIME 2000 141 (SCR/TD) Stacked 142 (SCR/TD) Kuparuk 1H-104 ConocoPhillips TSM 700 Arctic Fox #1 Stacked

Hilcorp Alaska LLC Rig No.1 Milne Point Hilcorp Alaska LLC

Kuukpik Drilling 5 Deadhorse Available

Nabors Alaska DrillingAC Coil Hybrid CDR-2 (CTD) Stacked in Deadhorse BPAC Coil CDR-3 (CTD) Kuparuk, 1H-21 ConocoPhillipsDreco 1000 UE 2-ES (SCR-TD) Stacked AvailableMid-Continental U36A 3-S Stacked AvailableOilwell 700 E 4-ES (SCR) Stacked AvailableDreco 1000 UE 7-ES (SCR/TD) Stacked ConocoPhillipsDreco 1000 UE 9-ES (SCR/TD) Stacked ConocoPhillipsOilwell 2000 Hercules 14-E (SCR) Deadhorse AvailableOilwell 2000 Hercules 16-E (SCR/TD) Stacked Brooks Range Petroleum Oilwell 2000 Canrig 1050E 27-E (SCR-TD) Stacked Glacier Oil & Gas Oilwell 2000 33-E Deadhorse AvailableAcademy AC Electric CANRIG 99AC (AC-TD) Stacked RepsolOIME 2000 245-E (SCR-ACTD) Stacked ENIAcademy AC electric CANRIG 105AC (AC-TD) Stacked in Deadhorse Doyon LtdAcademy AC electric Heli-Rig 106AC (AC-TD) Stacked Great Bear Petroleum

Nordic Calista ServicesSuperior 700 UE 1 (SCR/CTD) Prudhoe Bay AvailableSuperior 700 UE 2 (SCR/CTD) Prudhoe Bay AvailableIdeco 900 3 (SCR/TD) Prudhoe Bay AvailableRig Master 1500AC 4 (AC/TD) Oliktok Point ENI

Parker Drilling Arctic Operating Inc. NOV ADS-10SD 272 Prudhoe Bay DS 18 BPNOV ADS-10SD 273 Prudhoe Bay DSW-59 BP

North Slope - Offshore

BPTop Drive, supersized Liberty rig Inactive BP

Doyon DrillingSky top Brewster NE-12 15 (SCR/TD) Spy Island NN-01 ENI

Nabors Alaska DrillingOIME 1000 19AC (AC-TD) Cold Stacked Caelus Energy LLC

Cook Inlet Basin – Onshore

BlueCrest Alaska Operating LLCLand Rig BlueCrest Rig #1 Anchor Point, BlueCrest Alaska Operating LLC drilling production section of H14

Glacier Oil & Gas Rig 37 West McArthur River Unit Workover Glacier Oil & Gas

All American Oilfield LLCIDECO H-37 AAO 111 In All American Oilfield’s yard in Kenai, Alaska Available

Aurora Well ServicesFranks 300 Srs. Explorer III AWS 1 Stacked out west side of Cook Inlet Available

SaxonTSM-850 147 Stacked Hilcorp Alaska LLCTSM-850 169 Stacked Hilcorp Alaska LLC

Cook Inlet Basin – Offshore

Hilcorp Alaska LLCNational 110 C (TD) Platform C, Stacked Hilcorp Alaska LLC Rig 51 Steelhead Platform, Stacked Hilcorp Alaska LLC Rig 51 Monopod Platform, Drilling Hilcorp Alaska LLC Spartan Drilling Baker Marine ILC-Skidoff, jack-up Spartan 151, Stacked Seward

Furie Operating AlaskaRandolf Yost jack-up Nikiski, OSK dock Furie

Glacier Oil & GasNational 1320 35 Osprey Platform, activated Glacier Oil & Gas

Mackenzie Rig Status

Canadian Beaufort Sea

SDC Drilling Inc.SSDC CANMAR Island Rig #2 SDC Set down at Roland Bay Available

Central Mackenzie ValleyAkitaTSM-7000 37 Racked in Norman Wells, NT Available

Alaska - Mackenzie Rig ReportThe Alaska - Mackenzie Rig Report as of August 30, 2018.

Active drilling companies only listed.

TD = rigs equipped with top drive units WO = workover operations CT = coiled tubing operation SCR = electric rig

This rig report was prepared by Marti Reeve

Baker Hughes North America rotary rig counts* Aug. 24 Aug. 17 Year AgoUnited States 1,044 1,057 940Canada 229 212 217Gulf of Mexico 16 19 17

Highest/LowestUS/Highest 4530 December 1981US/Lowest 404 May 2016 *Issued by Baker Hughes since 1944

JUDY

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4 PETROLEUM NEWS • WEEK OF SEPTEMBER 2, 2018

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OWNER: Petroleum Newspapers of Alaska LLC (PNA)Petroleum News (ISSN 1544-3612) • Vol. 23, No. 35 • Week of September 2, 2018

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FINANCE & ECONOMYEnbridge tops up Spectra offer by 10%

Canadian multinational energy transportation company Enbridge has dug

deeper into its pockets to sweeten its bid to make a complete takeover of Spectra

Energy Partners for $4.3 billion, 10 percent more than its initial offer.

Enbridge, which already owns 83 percent of the Houston-based unit of

Spectra, is eager to reduce complexity in

the wake of its US$37 billion takeover of

Spectra Energy, gaining control of a vast

network of North American pipelines.

Spectra Energy Partners is a master lim-

ited partnership, MLP, and owns interests

in pipeline and storage facilities for natural

gas and crude oil.

Enbridge said acceptance of its latest

offer would deal with a U.S. tax ruling that

stopped MLPs from claiming allowances on fees charged to companies which

ship crude.

The change reduced the appeal of exploiting the MLPs to help fund billions of

dollars in growth projects and prompted Enbridge to initiate buyout offers earlier

this year.

Calgary-based Enbridge is selling assets and restructuring operations as part of

its C$22 billion program of major projects, including the C$9 billion Line 3 oil

pipeline from Alberta to Superior, Wisconsin, that replaces a 60-year-old corroded

line and double capacity to 760,000 barrels per day.

So far this year Enbridge has sold assets for C$7.5 billion, including Canadian

natural gas gathering and processing facilities — a move welcomed by bond-rat-

ing agencies.

—GARY PARK

Enbridge said acceptance of itslatest offer would deal with aU.S. tax ruling that stopped

MLPs from claimingallowances on fees charged tocompanies which ship crude.

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

State OKs Seaviewexploration plan

By KRISTEN NELSONPetroleum News

T he Alaska Department of Natural

Resources Division of Oil and Gas

has approved a lease plan of operations

for the exploration phase of Hilcorp

Alaska’s Seaview pad.

Hilcorp applied in late May for con-

struction of the Seaview pad on the south-

ern Kenai Peninsula near Anchor Point,

telling the division it planned to drill two

exploration wells from the new pad. The

company had permitted and drilled seven

shallow stratigraphic test wells in the area

last summer and began permitting activi-

ties early in the year for the pad and

exploration wells.

The proposed wells, Seaview 8 and 9,

will be drilled within ADL 392667, the

division said Aug. 24 in approving the

exploration phase of the project. Work

was planned to begin this summer and

end in early November, although the orig-

inal schedule, with pad construction pro-

posed to begin in mid-July, has slipped.

The division said the wellbore loca-

tions for the two wells “were derived

from stratigraphic wells drilled on private

lands near ADL 392667 and other prior

wells drilled in the surrounding area.”

The Seaview 8 will extend beyond ADL

392667, the state said, exploring for oil

on fee simple land.

The state said there are three separate

stages for each well, beginning with the

directional drilling and insertion of sur-

face casing through subsurface of poten-

tial hydrocarbon-bearing zones within the

Lower Sterling and Beluga formations,

with well evaluation including downhole

instrumentation. Well control equipment

and casing will isolate gas-bearing zones.

In stage two the well will be deepened

beyond the state lease with a lateral hori-

zontal evaluating the Lower Tyonek,

Hemlock and deeper formations on fee

simple lands.

The third stage would involve evaluat-

ing potential hydrocarbon reservoirs by

perforating and flow-back testing, follow-

ing which the well may be temporarily

secured or formally suspended while data

is evaluated.

The division said the first 5,500 feet of

the Seaview 8 would be perforated to

evaluate gas zones, which are partially

within ADL 392667, while the bottom-

hole location, on fee simple land, would

be evaluated for oil resources.

The division said the Seaview 9 would

be drilled some 10,000 feet measured

depth northwest of the pad and is a gas

exploration well only.

Pad specificsExisting access roads will be used and

pad construction will be within an active

mine site, so no rehabilitation is planned,

with cleanup work required to be done to

the satisfaction of the private landowner

and any applicable agencies and/or stake-

holders.

The pad is within one-half mile of the

Anchor River, with the exploration tar-

gets of the wells bounded by the one-half

mile Cook Inlet buffer to the west and the

one-half mile Anchor River buffer to the

east.

Environmental and social impact is

mitigated by the fact that the pad location

has already been disturbed, is an active

mine site with ongoing activities and will

result in no loss of wetlands or wildlife

habitat.

The primary target of the Seaview 8

well is gas; the target of the Seaview 9

well is only gas.

The division said the waiver allowing

the pad within one-half mile of the

Anchor River is appropriate because no

other location is practicable, with

Hilcorp’s proposal for locating the pad

offering the smallest possible extent of

environmental impact within ADL

392667.

Proposed facilities are temporary and

the gravel drill pad will be constructed at

the western extent of the parcel to mini-

mize the distance from the Anchor River

and buffer sound impacts to landowners

to the south and west.l

The division said the wellborelocations for the two wells “werederived from stratigraphic wells

drilled on private lands near ADL392667 and other prior wells

drilled in the surrounding area.”

PETROLEUM NEWS • WEEK OF SEPTEMBER 2, 2018 5

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l G O V E R N M E N T

A pause on tighterefficiency standardsDOT and EPA propose to freeze fuel efficiency standards forlight vehicles at 2020 levels for model years 2021 through 2026

By ALAN BAILEYPetroleum News

T he U.S. Department of Transportation

and the Environmental Protection

Agency have proposed to call a halt to the

further tightening of fuel efficiency standards

for light vehicles. In a notice of proposed

rulemaking, published in the Federal

Register on Aug. 28, the agencies said that

they propose to lock the standards for cars

and light-duty trucks for model years 2021

through 2026 at the standards set for 2020.

The proposed rule would set in motion a

process for taking comments on possible

alternatives for future standards. The agen-

cies have already modeled several options

for the standards, including the freeze on

standards that they now propose.

Under federal statutes, the agencies have

to set fuel efficiency standards for road

vehicles. The standards are set in five-year

increments.

In 2012 the Obama administration

issued standards for model years 2017 and

beyond, tightening the standards as part of

the administration’s policies aimed at

reducing U.S. greenhouse gas emissions.

However, under the terms of the appropriate

statutes, at that time the administration

could not enforce the standards beyond

2021.

First step in new standardsThe proposed new rule represents the

first step in setting enforced standards for

the 2021 to 2026 years.

The agencies say that the current strin-

gent standards have been a factor in the ris-

ing cost of new automobiles, putting new

automobiles out of reach for many

American families. And, since a study by

the National Highway Traffic Safety

Administration shows that new vehicles

tend to be safer than older vehicles, the abil-

ity of more people to purchase new vehicles

will increase road safety as well as improv-

ing overall fuel efficiency for the vehicle

fleet, the agencies say.

“There are compelling reasons for a new

rulemaking on fuel economy standards for

2021-2026,” said Secretary of

Transportation Elaine Chao. “More realistic

standards will promote a healthy economy

by bringing newer, safer, cleaner and more

fuel-efficient vehicles to U.S. roads and we

look forward to receiving input from the

public.”

“We are delivering on President Trump’s

promise to the American public that his

administration would address and fix the

current fuel economy and greenhouse gas

emissions standards,” said EPA Acting

Administrator Andrew Wheeler. “Our pro-

posal aims to strike the right regulatory bal-

ance based on the most recent information

and create a 50-state solution that will

enable more Americans to afford newer,

safer vehicles that pollute less. More realis-

tic standards can save lives while continu-

ing to improve the environment. We value

the public’s input as we engage in this

process in an open, transparent manner.”

Concerns raisedThe Environmental Defense Fund has

responded to the proposals by commenting

that a freeze on the fuel efficiency standards

could eliminate the possibility of cutting as

much as 140 million metric tons of carbon

dioxide emissions, just in 2030. Moreover,

the environmental organization said, by not

pursuing further fuel efficiency, American

companies will lose ground in the competi-

tive global market for automobiles.

According to an Associated Press report,

Sen. Tom Carper, D-Delaware, has accused

the Trump administration of supporting the

oil industry to the detriment of the rest of

society.

“American businesses, consumers and

our environment are all losers under this

plan,” Carper said. “The only clear winner

is the oil industry. It’s not hard to see whose

side President Trump is on.” l

The agencies say that the currentstringent standards have been afactor in the rising cost of new

automobiles, putting newautomobiles out of reach for many

American families.

PIPELINES & DOWNSTREAMJudge rules developer can’t sue Earth First

A federal judge has dismissed a second defendant from a $1 billion racketeer-

ing lawsuit that the developer of the Dakota Access oil pipeline filed against envi-

ronmental groups, leaving Greenpeace as the only remaining group facing the

claim.

Texas-based Energy Transfer Partners failed to make a case that Earth First is

an entity that can be sued, U.S. District Judge Billy Roy Wilson said in a ruling

dated Aug. 22.

The Center for Constitutional Rights had argued that Earth First is a philoso-

phy or movement similar to Black Lives Matter, and thus can’t be sued. ETP

unsuccessfully tried to serve the lawsuit to Florida-based Earth First Journal,

which argued that it wasn’t the same as the movement.

Wilson said that rather than clarifying the matter, an amended complaint filed

by ETP earlier in August was “wholly insufficient” in advancing its case under the

Racketeer Influenced and Corrupt Organizations Act that Earth First “allegedly

provided hundreds of thousands of dollars to fund an international terrorist, drug-

smuggling RICO enterprise.”

Center for Constitutional Rights attorney Pamela Spees applauded the ruling,

calling the lawsuit “far-fetched.” ETP officials have said the company doesn’t

comment on active litigation.

Suits last AugustETP sued Earth First, BankTrack and Greenpeace last August, alleging that

they worked to undermine the $3.8 billion pipeline that’s now shipping North

Dakota oil to a distribution point in Illinois. Opposition to the pipeline by groups

and American Indian tribes who feared environmental harm inspired large

protests in southern North Dakota and resulted in 761 arrests over a six-month

span in late 2016 and early 2017.

In July, Wilson ruled that the company had no claim against BankTrack. The

Dutch environmental group had urged banks not to finance the pipeline, which

Wilson concluded did not amount to radical ecoterrorism.

Wilson gave Greenpeace until Sept. 4 to file its response to ETP’s amended

complaint, which added five individual defendants: a man who is allegedly affil-

iated with Greenpeace, two Iowa women who have publicly claimed to have van-

dalized the pipeline, and two people associated with the Red Warrior Camp, a

protest group alleged to have advocated aggressive tactics such as arson. There

are also 20 unnamed defendants listed as John or Jane Does. Wilson on Aug. 22

gave company attorneys 30 days to identify them or have them dismissed as

defendants.

—ASSOCIATED PRESS

By WILL WEISSERTAssociated Press

As the nation plans new defenses

against the more powerful storms

and higher tides expected from climate

change, one project stands out: an ambi-

tious proposal to build a nearly 60-mile

“spine” of concrete seawalls, earthen bar-

riers, floating gates and steel levees on

the Texas Gulf Coast.

Like other oceanfront projects, this

one would protect homes, delicate

ecosystems and vital infrastructure, but it

also has another priority — to shield

some of the crown jewels of the petrole-

um industry, which is blamed for con-

tributing to global warming and now

wants the federal government to build

safeguards against the consequences of it.

The plan is focused on a stretch of

coastline that runs from the Louisiana

border to industrial enclaves south of

Houston that are home to one of the

world’s largest concentrations of petro-

chemical facilities, including most of

Texas’ 30 refineries, which represent 30

percent of the nation’s refining capacity.

Texas is seeking at least $12 billion for

the full coastal spine, with nearly all of it

coming from public funds. In July, the

government fast-tracked an initial $3.9

billion for three separate, smaller storm

barrier projects that would specifically

protect oil facilities.

That followed Hurricane Harvey,

which roared ashore last Aug. 25 and

swamped Houston and parts of the coast,

temporarily knocking out a quarter of the

area’s oil refining capacity and causing

average gasoline prices to jump 28 cents

a gallon nationwide. Many Republicans

argue that the Texas oil projects belong at

the top of Washington’s spending list.

“Our overall economy, not only in

Texas but in the entire country, is so much

at risk from a high storm surge,” said

Matt Sebesta, a Republican who as

Brazoria County judge oversees a swath

of Gulf Coast.

Should US taxpayers pay?But the idea of taxpayers around the

country paying to protect refineries worth

billions, and in a state where top politi-

cians still dispute climate change’s valid-

ity, doesn’t sit well with some.

“The oil and gas industry is getting a

free ride,” said Brandt Mannchen, a

member of the Sierra Club’s executive

committee in Houston. “You don’t hear

the industry making a peep about paying

for any of this and why should they?

There’s all this push like, ‘Please Senator

Cornyn, Please Senator Cruz, we need

money for this and that.’”

Normally outspoken critics of federal

spending, Texas Sens. John Cornyn and

Ted Cruz both backed using taxpayer

funds to fortify the oil facilities’ protec-

tions and the Texas coast. Cruz called it

“a tremendous step forward.”

Federal, state and local money is also

bolstering defenses elsewhere, including

on New York’s Staten Island, around

Atlantic City, New Jersey, and in other

communities hammered by Superstorm

Sandy in 2012.

Construction could begin soonConstruction in Texas could begin in

several months on the three sections of

storm barrier. While plans are still being

finalized, some dirt levees will be raised

to about 17 feet high, and 6 miles of 19-

foot-tall floodwalls would be built or

strengthened around Port Arthur, a Texas-

Louisiana border locale of pungent chem-

ical smells and towering knots of steel

pipes.

The town of 55,000 includes the

Saudi-controlled Motiva oil refinery, the

nation’s largest, as well as refineries

owned by oil giants Valero Energy Corp.

and Total S.A. There are also almost a

dozen petrochemical facilities.

“You’re looking at a lot of people, a lot

of homes, but really a lot of industry,”

said Steve Sherrill, an Army Corps of

Engineers resident engineer in Port

Arthur, as he peered over a Gulf tributary

lined with chunks of granite and metal

gates, much of which is set to be rein-

forced.

The second barrier project features

around 25 miles of new levees and sea-

walls in nearby Orange County, where

Chevron, DuPont and other companies

have facilities. The third would extend

and heighten seawalls around Freeport,

home to a Phillips 66 export terminal for

liquefied natural gas and nearby refinery,

as well as several chemical facilities.

Focus on refineriesThe proposals approved for funding

originally called for building more pro-

tections along larger swaths of the Texas

coast, but they were scaled back and now

deliberately focus on refineries.

“That was one of the main reasons we

looked at some of those areas,” said Tony

Williams, environmental review coordi-

nator for the Texas Land Commissioner’s

Office.

Oil and chemical companies also

pushed for more protection for surround-

ing communities to shield their work-

forces, but “not every property can be

protected,” said Sheri Willey, deputy

chief of project management for the

Army Corps of Engineers’ upper Texas

district.

“Our regulations tell us what benefits

we need to include, and they have to be

national economic benefits,” Willey said.

Once work is complete on the three

sections, they could eventually be inte-

grated into a larger coastal spine system.

In some places along Texas’ 370-mile

Gulf Coast, 18 feet is lost annually to ero-

sion, threatening to suck more wetlands,

roads and buildings into rising seas.

Protecting a wide expanse will be

expensive. After Harvey, a special Texas

commission prepared a report seeking

$61 billion from Congress to “future

proof” the state against such natural dis-

l G O V E R N M E N T

Seawall would protect homes, oil industry

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Better.

Texas is seeking at least $12billion for the full coastal spine,with nearly all of it coming from

public funds. In July, thegovernment fast-tracked an initial

$3.9 billion for three separate,smaller storm barrier projects that

would specifically protect oilfacilities.

see SEAWALL PROJECT page 9

By BECKY BOHRERAssociated Press

The path to the governor’s office in

Alaska this year may hinge on the oil

check given to state residents.

Each year, the state distributes checks

just for living here — residents’ share of

the state’s oil wealth. For some, it’s discre-

tionary money used for new toys, like big

screen TVs, or socked into savings, while

for others, particularly those who are

lower-income or who live in high-cost

rural Alaska, it’s a part of their income.

The checks went out like clockwork

until 2016, when in the midst of legislative

gridlock over how to address a multibil-

lion-dollar budget deficit Gov. Bill Walker

cut the size of everyone’s check by about

half. He defended the move, along with

additional budget vetoes, as necessary to

preserve the state’s savings. Everyone

could still get a check, he said, just not as

big.

His action, upheld by the state Supreme

Court, set a precedent: Since then, law-

makers have not followed the formula in

state law for calculating the Alaska

Permanent Fund dividend checks. Some

have insisted doing so, while the state is

still in a deficit, would be fiscally reckless.

But the decision has brought with it politi-

cal backlash, which Walker, an independ-

ent, hopes to withstand as he faces a tough

re-election bid against conservative former

state Sen. Mike Dunleavy and Democratic

former U.S. Sen. Mark Begich.

DunleavyDunleavy said people are angry that a

decision of that magnitude was made with-

out their involvement. He supports the for-

mula in state law for calculating the check

and does not support changing that with-

out public involvement, including an advi-

sory vote. That’s because if the Legislature

passes taxes or changes to the checks and

citizens don’t agree, they can pursue a ref-

erendum to try to overturn them, he said.

Money for the checks comes from the

earnings of the oil-wealth fund, the Alaska

Permanent Fund. Legislators have long

resisted using fund earnings to pay for

state government. But after blowing

through billions of dollars in savings amid

gridlock over how best to fill the deficit

and shunning taxes, they ran short of

options and agreed earlier this year to start

using fund earnings to fill much of the

hole.

BegichThe fund’s principal is constitutionally

protected, but earnings can be spent with a

simple majority. Begich favors moving

billions of dollars from fund earnings to

the fund’s principal to ensure it isn’t “sub-

ject to the whims of elected officials” and

limiting the amount withdrawn each year

based on a percentage of the fund’s market

value. Part of the money drawn would go

toward a dividend and part would go

toward funding public education.

He said the dividend should be consti-

tutionally protected, an issue he said he

would make a priority.

“You have to get that Permanent Fund

Dividend issue resolved one way or the

other,” he told a small group at a Juneau

meet-and-greet last week. If not, lawmak-

ers will keep fighting over it and won’t

have time to think about other long-term

issues, he said.

Walker said he’s not opposed to

enshrining some form of dividend in the

constitution. But he doesn’t want to see an

upper limit and whatever is settled on

should be sustainable, he said.

The permanent fund is a nest egg, seed-

ed with oil money and grown through

investments. Lawmakers settled on a

check of $1,600 for this year. That’s about

$1,050 less than what Walker’s budget

office earlier this year predicted the

amount would be if a full dividend were

paid out.

MallottLt. Gov. Byron Mallott, a Democrat,

said Walker’s action saved the dividend

for the future. He said it allowed for pas-

sage of legislation calling for structured

withdrawals of permanent fund earnings.

“And many, many, many more

Alaskans understand that than those who

are trying to create a crisis from it,”

Mallott said.

The bill retained the existing formula in

state law for calculating dividends but

since that has been ignored the past three

years, there’s no guarantee it will be fol-

lowed in the future.

Monte Wallace, a Dunleavy supporter,

said the Wasilla Republican “will give our

PFD back to us.” PFD is permanent fund

dividend. She said Walker has “destroyed

Alaska, the way it was,” citing concerns

she has with crime.

Therese Thibodeau, who attended

Begich’s coffee shop meet-and-greet in

Juneau and said she’s registered with the

Green party, said she supported Walker in

2014 and appreciated his action on the div-

idend. “I thought that’s a good thing,” she

said.

She said she was pleasantly surprised,

though, by what she heard from Begich,

particularly his thoughts on the budget.

“Now, I’m more on the fence than I was

when I walked in,” she said. l

l G O V E R N M E N T

Governor’s race may hinge on PFD checks

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PIPELINES & DOWNSTREAMJudge confirms city’s right in lawsuit

A Maine city’s ordinance prohibiting bulk loading of crude oil onto tankers

does not violate the U.S. Constitution.

That was the Aug. 24 ruling of a federal court that had been considering South

Portland’s “Clear Skies” ordinance. Portland Pipe Line Corp. challenged the ordi-

nance on the grounds that it violated clauses of the Constitution that give

Congress sole power over foreign and interstate trade.

The Portland Press Herald reports the ordinance blocked the company from

reversing the flow of its 236-mile underground pipeline. The pipeline has carried

foreign crude from harbor terminals in South Portland to Canadian refiners for

decades.

The ruling followed a four-day June trial in U.S. District Court in Portland.

South Portland’s City Council banned bulk loading of crude oil on the city water-

front in 2014.

—ASSOCIATED PRESS

The permanent fund is a nest egg,seeded with oil money and grown

through investments.

court costs incurred by Alberta and

Kinder Morgan.

Although the final bills have not been

made public, they are expected to reach

millions of dollars.

But Burnaby Mayor Derek Corrigan is

undeterred, insisting his city will “contin-

ue to oppose this project with all the legal

means available to us,” including four

pending legal challenges.

Greenpeace campaigner Mike

Hudema said the court verdict allows the

Canadian government to override munic-

ipalities that are “just trying to protect the

health and safety of our citizens.”

Government stands by decisionA spokesman for federal Natural

Resources Minister Amarjeet Singh said

the government stands by its decision to

buy the existing Trans Mountain link and

related infrastructure for C$4.5 million,

plus about C$6.3 billion in expansion

costs, noting the additional 590,000 bar-

rels per day of capacity is needed to estab-

lish new markets for Canadian crude.

Although many British Columbia First

Nations oppose the pipeline and are par-

ticipants in a Federal Court of Appeal

challenge, 43 aboriginal communities

have signed benefit agreements and wel-

comed the Supreme Court’s verdict.

Cheam First Nation Chief Ernie Grey

said there is a “growing interest on the

part of indigenous people to take out a

stake in the pipeline.”

“We have the option of buying shares,

but my impression from the leadership in

Alberta, Saskatchewan and B.C. is that

they want a substantial interest in the

pipeline,” he said.

Margot Young, a law professor at the

University of British Columbia, said the

Supreme Court’s decision reinforces that

federal tribunals supersede municipal

governments.

She said it was not surprising that that

the top court did not hear Burnaby’s

appeal, although she said it may hear an

appeal from the B.C. government.

Imports, exports both upWhile the legal fights continue,

imports of gasoline, diesel and jet fuel

through the Port of Vancouver climbed

sharply over the first half of 2018 and

exports of petroleum products also posted

a strong gain, with combined inbound and

outbound volumes up 40.3 percent over

the same period of 2017.

The port authority said oil shipments

for all of 2017 were 1.8 million metric

tons, or 12.6 million barrels, compared

with 1.2 million metric tons, or 8.5 million

barrels in 2016.

Kinder Morgan, which owns the Trans

Mountain pipeline pending an expected

sale to the Canadian government, said the

majority of shipments leaving the compa-

ny’s Westridge Marine Terminal at

Burnaby in Greater Vancouver are des-

tined for the United States, although one

tanker went to Korea and one to China.

“The mix of products and destinations

varies from year to year and is based on

market demand,” Kinder Morgan told the

Vancouver Sun.

Robyn Allan, an independent econo-

mist, said the market conditions make it

attractive for California refineries —

which are looking for new feedstocks to

replace declining supplies from Alaska —

to take advantage of the over-subscribed

Trans Mountain system, noting that

reflects the price of US$26 a barrel

between Western Canada Select heavy oil

and the benchmark West Texas

Intermediate crude which has been close

to US$65 recently.

The port authority’s Chief Executive

Officer Robin Silvester said the import

and export volumes of crude underline

how reliant the Vancouver region remains

on fossil fuels, with the inbound crude

almost exclusively used by consumers.

The Westridge terminal can handle

both imports and exports, making it the

largest volume entry and exit point, but

four other terminals, including a former

Chevron refinery, also play a role in the

crude business. l

8 PETROLEUM NEWS • WEEK OF SEPTEMBER 2, 2018

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continued from page 1

COURT VERDICT

potential infrastructure sharing with

ConocoPhillips Alaska and portfolio

growth options with Armstrong, Repsol and

others.

The initial focus, on Pikka Nanushuk

development, involves integrating recent

technical advances in drilling and comple-

tion techniques, Botten said. The project is

on track for FEED entry, front-end engi-

neering and development, in the second

quarter of next year, leading to a final

investment decision in mid-2020, he said,

with the final scope of Pikka Nanushuk

development the determination of whether

the facility will be sized for 80,000 barrels

per day or 100,000 bpd, a determination

which will be made based on 2019 season

drilling results.

First oil is expected in 2023.

ExpansionThe second focus, on Nanushuk expan-

sion in the Horseshoe area south of Pikka,

has the potential of 300 million barrels of

resource, Botten said. That work, planned

for 2019, will involve seismic reprocessing,

reservoir modeling and data trades with

ConocoPhillips with drilling planned for

2020.

For the third focus, exploration, he said

Oil Search has identified a number of

opportunities which it is prioritizing as

potential tie-in opportunities to the core

development. That would be a three-plus

year program.

The last focus, new business, is on build-

ing strategic relationships, something

Botten said the company was working to

accomplish in what he called a reasonable

timeframe. Presentation information cate-

gorized this phase as strategic relationships

and listed the potential for infrastructure

sharing with ConocoPhillips Alaska, and

portfolio growth options with Armstrong,

Repsol and others.

Botten said Oil Search is having what he

characterized as very successful discussions

with ConocoPhillips around field develop-

ment, including use of common infrastruc-

ture and how the fields will potentially be

developed.

Focus on PikkaThe immediate focus is a successful

appraisal of the Pikka unit.

He noted recent drilling by

ConocoPhillips at Putu has highlighted

reservoir continuity and the potential for

upside resources in the field.

This winter’s drilling will be at the Pikka

B and Pikka C, with a goal of increasing

proven resources from the 500 million bar-

rels assumed in the acquisition, targeting an

additional 250 million barrels. The Pikka B

and Pikka C locations have been identified

and the sites surveyed, both northeast of

Nuiqsut as shown on a map of the

Nanushuk reservoir extent that was part of

the company’s presentation. Drilling sites

were not specifically identified and the

Alaska Oil and Gas Conservation

Commission has not yet issued drilling per-

mits, which will identify drilling locations

by section, township and range.

Drilling is expected to begin by the end

of the year and be completed in April.

Percentage of ownershipLast year Oil Search purchased a portion

of Armstrong Energy and GMT

Exploration’s interests at Pikka and

Horseshoe, paying $400 million for a 25.5

percent interest in the Pikka unit and adja-

cent exploration acreage and 37.5 percent

interests in the Horseshoe block and the

Hue shale, with an option, exercisable until

June 30, 2019, to purchase all of Armstrong

and GMT’s remaining interest in the

Horseshoe block (25.5 percent and 37.5

percent respectively) as well as an addition-

al 25.5 percent interest in adjacent explo-

ration acreage and 37.5 percent in the Hue

shale, for $450 million.

In its financial overview Oil Search

specified the acquisition of Alaska assets at

US$416 million and said the Alaska

Nanushuk development would be done

with new project finance facilities.

Repsol has partnered with Armstrong

and GMT, holding a 49 percent interest in

Pikka and Horseshoe.

Asked about the percentage of owner-

ship which Oil Search wants, Botten said

they are already preparing a data room and

a team to support divestment, looking at an

ownership of about 30 percent long term.

A slide from the presentation says the

company is beginning the process for cap-

turing the Armstrong value option, aligning

with Repsol to attract quality third parties

continued from page 1

OIL SEARCH

see OIL SEARCH page 12

with the laying of the field’s subsea

pipeline taking place during the following

winter and first oil from the field perhaps

flowing in 2022. The plan is to ultimately

drill 16 wells, presumably a combination

of production, injection and disposal

wells.

Production would likely begin at a rate

of 10,000 to 15,000 barrels per day, peak-

ing at perhaps 60,000 to 70,000 bpd after

about two years. Peak gas production is

anticipated to be around 120 million

cubic feet per day. Hilcorp thinks that the

field holds around 120 million barrels of

recoverable oil and field life is anticipated

to be 15 to 20 years.

Production facilities on the island

would deliver sales grade crude oil into

the subsea pipeline for shipment to shore.

Produced gas would be used for fuel on

the island, for injection into the field’s

reservoir and for gas lift in production

wells. Treated seawater mixed with pro-

duced water would also be injected into

the reservoir for pressure maintenance.

A mine site west of the Kadleroshilik

River would act as source of gravel for

the construction project. Winter construc-

tion activities would require four ice

roads and three ice pads. Gravel would be

moved by ice road for island construction

during the winter. Large equipment, such

as the drilling rig, would be delivered by

barge to the island in the summer. Hilcorp

expects to be able to truck most of the

modules, buildings and materials to the

North Slope, for shipment from Prudhoe

Bay West Dock, or from the Endicott

island. However, some equipment may be

shipped by barge from Dutch Harbor.

Other options consideredThe EIS considers other development

options, including a couple of alternative

possible locations for the production

island, and the possibility of installing

field processing facilities on the Endicott

satellite drilling island, rather than on

Liberty island. The EIS dismisses as tech-

nically and economically infeasible an

option involving ultra-extended reach

drilling from the Endicott island, an

option that BP had proposed in 2005. A

“no action” alternative would eliminate

the economic benefit to be gained from

developing the field.

The Boulder Patch, a seabed feature of

considerable environmental significance,

played a role in assessing the potential

environmental impacts of some options.

Although the proposed plan places the

artificial island outside the Boulder Patch,

alternative island locations could move

the island farther from the environmental-

ly sensitive area. But these options would

raise other issues. One option, for exam-

ple, would place the subsea oil export

pipeline in an area susceptible to seafloor

scouring associated with the nearby

Kadleroshilik River delta.

Discovered by ShellShell Oil Co. discovered oil in the area

of the Liberty field between 1982 and

1987, through the drilling of four wells

into the Kekiktuk formation from two

artificial gravel islands. The Kekiktuk is

the reservoir rock for the Endicott oil

field to the northwest. In 1997 BP con-

firmed the existence of the field through

the drilling of the Liberty No. 1 explo-

ration well.

In 1998 BP proposed developing the

field from an artificial gravel island.

However, in 2001 the company re-evalu-

ated that plan and, in 2005, came up

instead with its plan to develop the field

using ultra-extended reach drilling from

Endicott. The company moved ahead

with that plan, expanded the Endicott

satellite island and installed a purpose-

built drilling rig for the project. However,

following technical problems and some

issues relating to the Deepwater Horizon

disaster, the company cancelled the proj-

ect in 2012.

In 2014 BP sold 50 percent ownership

of the field to Hilcorp. Hilcorp became

field operator and has since moved ahead

with planning the development of the

field along similar lines to BP’s original

1998 concept. l

PETROLEUM NEWS • WEEK OF SEPTEMBER 2, 2018 9

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

Companies involved in Alaska’s oil and gas industryAdvertiser Index

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

asters, without mentioning climate change, which scien-

tists say will cause heavier rains and stronger storms.

Local matching requiredTexas has not tapped its own rainy day fund of around

$11 billion. According to federal rules, 35 percent of

funds spent by the Army Corps of Engineers must be

matched by local jurisdictions, and the GOP-controlled

state Legislature could help cover such costs. But such

spending may be tough for many conservatives to swal-

low.

Texas “should be funding things like this itself,” said

Chris Edwards, an economist at the libertarian Cato

Institute. “Texans are proud of their conservatism, but,

unfortunately, when decisions get made in Washington,

that frugality goes out the door.”

State officials counter that protecting the oil facilities

is a matter of national security.

The effects of the next devastating storm could be felt

nationwide,” Rep. Randy Weber, a fiercely conservative

Republican from suburban Houston who has nonetheless

authored legislation backing the coastal spine.

Major oil companies did not return messages seeking

comment on funding for the projects. But Suzanne

Lemieux, midstream group manager for the American

Petroleum Institute, said the industry already pays into

programs such as the federal Harbor Maintenance Trust

Fund and the Waterways Trust Fund, only to see

Congress divert that money elsewhere.

“Do we want to pay again, when we’ve already paid

a tax without it getting used? I’d say the answer is no,”

she said.

Phillips 66 and other energy firms spent money last

year lobbying Congress on storm-related funding post-

Harvey, campaign finance records show, and Houston’s

Lyondell Chemical Co. PAC lobbied for building a

coastal spine.

“The coastal spine benefits more than just our indus-

try,” Bob Patel, CEO of LyondellBasell, one of the

world’s largest plastics, chemicals and refining compa-

nies, said in March. “It really needs to be a regional

effort.” l

continued from page 6

SEAWALL PROJECT

continued from page 1

LIBERTY EIS

Multiyear programDoyon has been conducting an oil and

gas exploration program in the Nenana

basin for a number of years — CIRI has

partnered with Doyon in the drilling of both

the Totchaket well and the previous well

drilled in the basin, the Toghotthele well,

drilled in 2016. The basin is conveniently

located close to the Parks Highway, to the

southwest of Fairbanks. Recently Doyon

has been particularly focusing on making an

oil discovery, although the basin is also

highly prospective for natural gas.

The Nenana basin, one of a number of

Alaska basins formed by the pulling apart of

the Earth’s crust, is filled with a huge thick-

ness of non-marine Tertiary sediments. Coal

seams and shales within the rock sequence

have the potential to source both oil and gas,

depending on the extent to which they are

heated at depth. There are sands with excel-

lent hydrocarbon reservoir potential, inter-

layered with shales that could form hydro-

carbon traps. In broad terms, the basin has a

northeast to southwest trending hourglass

shape, with a deep basin in the north and a

central saddle in the narrower, central part

of the basin, immediately west of the town

of Nenana. The depths reached in the

northerly section of the basin are thought to

be sufficient to have raised the temperatures

in the potential source rocks to levels con-

ducive to oil formation.

Three previous wellsDoyon and partners have previously

drilled three wells in the basin’s central sad-

dle, targeting potential traps identified from

seismic data. The hope was that hydrocar-

bons migrating up into the saddle from

deeper parts of the basin would have

become trapped. Although these wells

failed to discover viable pools of oil or gas,

the wells did encounter evidence of an

active petroleum system. The Toghotthele

No. 1 well, for example, drilled in 2016,

found multiple oil shows, as well as natural

gas. Some of that gas was “wet gas,” con-

taining natural gas liquids that must have

formed through the application of heat

rather than through microbial action on

organic material. But it seems that what

now appears to be a trapping structure had

formed after the oil had migrated through

the rocks.

The Nunivak No. 1 well, drilled in 2009,

also encountered some oil shows. And the

Nunivak No. 2 well, drilled in 2013, found

a 400-foot thick section of gas-bearing rock

that also contained too much water to be

commercially viable.

Focus on northerly prospectsWith the drilling of the Totchaket well,

attention shifted to the deeper more norther-

ly part of the basin, above the presumed oil

and gas kitchen. The well targeted the

Totchaket East prospect, one of five

prospects identified from 3-D seismic data

collected from a survey conducted in 2017.

Apparently the seismic displayed hydrocar-

bon indicators in all of the prospects. And

the mapping of subsurface rock units, using

seismic and gravity data, suggests that the

northern part of the basin may have more

reliable hydrocarbon migration pathways

than farther south, with an absence of the

uplift that may have disrupted hydrocarbon

trapping mechanisms in the central saddle.

—ALAN BAILEY

10 PETROLEUM NEWS • WEEK OF SEPTEMBER 2, 2018

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of Caelus Energy, told Petroleum News on Aug. 29:

“Caelus will not be conducting work at Smith Bay this

winter.”

In early 2016, Caelus claimed it made one of the

largest recent oil discoveries in Alaska or elsewhere

with its two Tulimaniq wells, announcing 6 billion to

10 billion barrels of oil in place.

Thus far, Caelus has not been able to conduct flow

tests for the oil pool.

Caelus has cited low oil prices and uncertainty over

production tax policy at the state level as its reasons for

not returning to the area.

Tulimaniq is far offshore. Reportedly, $90 million of

the $150 million it spent to drill the prospect’s two

wells was spent on logistics, requiring a $60 oil price to

develop the field, per Caelus.

Still, some government geologists are excited about

Tulimaniq.

Petroleum geologist Paul Decker from Alaska’s

Division of Oil and Gas talked to Petroleum News in

June about the nature and significance of the new finds.

Decker sees the new Nanushuk/Torok oil plays as open-

ing the possibility of further significant oil discoveries

to the west of the central North Slope. The plays may

also prove valuable as a geologic paradigm for oil

prospects in the newly opened 1002 area of the Arctic

National Wildlife Refuge, Decker said.

The three recent major finds consist of the

Pikka/Horseshoe trend in the Nanushuk in the Colville

River delta region, discovered by Armstrong and

Repsol and being developed by their partner Oil

Search, the Willow discovery in the Nanushuk of the

northeastern National Petroleum Reserve-Alaska, dis-

covered and headed to development by ConocoPhillips,

and Caelus’ major oil pool in the Torok under Smith

Bay, Decker said.

—KAY CASHMAN

Nutrien still actively seeking gas supply

NUTRIEN, WHICH WAS FORMED WITH THE

MERGER of Potash Corp. and Agrium in early January,

is still hoping to re-open its Kenai Peninsula fertilizer

facility, its Alaska manager Fred Werth told Petroleum

News Aug. 27.

A long-term natural gas supply

in Cook Inlet is crucial to re-open-

ing the facility, and Werth said

Nutrien is “actively engaged in

really trying to sort out” the situa-

tion.

“Gas price is our biggest chal-

lenge,” natural gas feedstock being

the highest cost component in the

manufacturing process, Werth told

PN in January.

The former Agrium facility employed 400 well-paid

Alaskans when in full operation. It closed in 2007,

when the Cook Inlet gas fields were in significant

decline and the facility was unable to secure enough

supply to operate. The inlet gas industry has since expe-

rienced a resurgence of gas exploration and production.

What Canada-based Nutrien, which trades as NTR

on the Toronto and New York stock exchanges, offers

natural gas producers is a stable, long-term gas con-

tract. Although the price Nutrien can justify would be

under current market value, which is currently high

compared to other markets, it would not be subject to

the fluctuations of consumer demand and thus allow

producers to make long-term development plans, Werth

said in January.

Agrium’s North Kenai/Nikiski facility had been the

second largest producer of ammonia and urea in the

United States, most of which was sold overseas to

South Korea, Mexico and Taiwan.

“The greatest advantage of the merger was that it

brought together Potash Corp. and Agrium’s marketing

and production strengths, making products more readily

available across North America,” Werth said in January,

noting the merged company traded all over the world.

The Alaska facility, consisting of two utility, two

ammonia and two urea plants, “is strategically located

in North Kenai on a deepwater port to distribute to the

Pacific Rim,” he said.

Potash and urea ammonia are used in caring for

crops. Potash adds potassium, while urea ammonia sup-

plies nitrogen.

The fastest developing markets for urea are

Southeast Asia and East Asia.

Urea is the most popular form of solid nitrogen fer-

tilizer, particularly in the developing regions of the

world. Currently, the Southwest Asian region consumes

more than 55 percent of the urea produced worldwide.

“They don’t need any special equipment to put urea

on their fields … they can put it on with a gunny sack

and a coffee can,” Werth explained in January.

Liquid nitrogen, which the North Kenai Nutrien

facility would also produce, is primarily used in North

America, as it is sprayed on. Before U.S. farmers used

nitrogen, their average yield was 100 bushels an acre

for corn; today production is 250 bushels per acre.

The re-opening of Agrium’s mothballed fertilizer

facility could provide a significant economic boost for

the region.

Reportedly, rehabilitating the facility for a restart

would cost about $350 million, whereas the cost for

Nutrien to construct a similar facility elsewhere in the

Pacific Rim could run $2-3 billion.

Werth did not confirm or discuss these estimates.

—KAY CASHMAN

More positive headlines for Alaska’s North Slope

ON AUG. 12 AND AUG. 23 OilPrice.com carried

upbeat stories about the renewal of Alaska North Slope

exploration, triggered by the discovery of the “massive”

Armstrong/Repsol Pikka oil field in the overlooked

Nanushuk formation in 2015.

OilPrice.com’s first story, “Why Is Big Oil So

Excited About Alaskan Crude?,” dwelled on the data

release of several previously overlooked oil deposits,

including Pikka, by the Alaska Division of Oil and Gas,

and provided details about the upcoming November

state lease sale.

“After years of diminishing returns in the once

mighty North Slope, Pikka is just one of three major

recent finds that revived interest in the North Slope,”

wrote Haley Zaremba, referring to Pikka, Willow and

Tulimaniq.

The second story, “Alaska’s Oil Renaissance,” refer-

enced new research from IHS Markit, showing “the

North Slope’s crude output could increase by as much

as a whopping 40 percent in the next eight years.”

The North Slope, “previously considered as a mature

basin, is now being touted in the media as the once and

future ‘super-basin’ thanks to an estimated 38 billion

barrels of oil equivalent in remaining recoverable

resources,” Zaremba wrote.

—KAY CASHMAN

continued from page 1

INSIDER

FRED WERTH

continued from page 1

WELL RESULTS

an Alaska Industrial Development and

Export Authority project to bring afford-

able natural gas to Fairbanks and its sur-

rounds. Fairbank gas utility, Interior Gas

Utility, will need the expanded LNG sup-

ply to support an anticipated increase in

the number of gas consumers in the

Fairbanks region.

Siemens under contract to Knik TribeSiemens would build the proposed

plant under contract to Knik Tribe, which

would own the project. Knik Tribe with

assistance from Siemens would capitalize

the project. IGU would sign a liquefaction

services agreement with Knik Tribe, pay-

ing for this service through a service

charge coupled with a volume-based lique-

faction fee for LNG delivered to an IGU

storage tank in Fairbanks. As currently

envisaged by Knik Tribe and Siemens,

IGU would pay for the transportation of

LNG to Fairbanks by railroad.

Thus, rather than funding the capital

cost of the LNG plant, as is envisaged for

the Titan plant expansion, IGU would pay

Knik Tribe a fee for the production and

delivery of LNG to Fairbanks. This

arrangement would presumably enable

IGU to avoid taking on additional debt in

conjunction with expanding the LNG sup-

ply. And Knik Tribe, as a federally recog-

nized tribe, would have access to federal

programs that could minimize the cost of

capital for the project, explained Kelly

Laurel, director for energy and infrastruc-

ture for Siemens Government

Technologies.

When the LNG plant goes into opera-

tion, the contract between Knik Tribe and

Siemens would result in the liquefaction

services agreement obligations for the

plant to, in effect, flow through to

Siemens.

Siemens officials said that Siemens has

already completed the front-end engineer-

ing and design for the proposed project. If

IGU is interested in moving forward with

the project, there are a number of details

around the interface between IGU’s opera-

tions and the LNG supply arrangements

that would need to be negotiated, Laurel

explained. That would lead to a memoran-

dum of understanding that would enable

Knik Tribe and Siemens to confirm the

LNG pricing model and move towards a

contract.

Three potential gas sourcesThe Siemens proposal includes a pric-

ing model using three potential sources of

natural gas for manufacturing LNG: the

gas supply assumed by IGU in its model-

ing of the Titan plant expansion; an alter-

native gas supply agreement negotiated by

Knik Tribe and Siemens; or a new gas sup-

ply from a wellhead gas resource adjacent

the proposed Houston LNG facility.

Knik Tribe and Siemens say that, with

regard to their own pipeline gas supply,

they are conducting confidential negotia-

tions with current suppliers of gas to

Enstar Natural Gas Co’s pipeline system (a

main Enstar gas transmission line runs not

far the proposed Houston LNG plant site).

IGU’s own assumed gas price for the LNG

supply for the Titan expansion is $7.72 per

mcf, the proposal says.

The proposal provides no information

about the potential wellhead gas resource

at the Houston site but says that this option

is being actively pursued, with a potential

cost of supply in the range of $3 to $5 per

mcf.

“As far as wellhead gas, we are invest-

ing in proving out the well right now,” a

Siemens official told the board.

In 2004 Evergreen Resources drilled

several shallow stratigraphic test wells or

core holes, testing for coalbed methane

resources in the Matanuska-Susitna

Borough. At least one of those wells was to

the immediate northwest of Houston. The

coalbed methane exploration program

came to an end shortly after the drilling,

following a political uproar from local res-

idents over land access and concerns about

potential pollution.

Siemens officials told the IGU board

that it sees its involvement in the proposed

Houston LNG plant as an anchor project

for more involvement by the company in

Alaska’s evolving economy. And the

industrial park where the plant would be

located has ample space for further indus-

trial development, should the LNG plant

come to fruition. Moreover, additional

LNG processing at the site for applications

other than the Fairbanks gas supply could

significantly reduce the unit cost of the

LNG.

Range of price possibilitiesThus the proposal presents a range of

possible prices for LNG delivered to

Fairbanks, depending on the nature of the

gas supply and the extent of the LNG

development. Modeling using IGU’s

assumed future gas demand profile for

Fairbanks and IGU’s assumed gas supply

pricing results in an anticipated price of

$17.98 per mcf for LNG delivered to the

Fairbanks storage tank. That price could

drop to $15.02 per mcf, depending on what

alternative pipeline delivered gas supply

Knik Tribe and Siemens may be able to

negotiate. The use of an on-site wellhead

gas supply could drop that price to $13.93.

A pipeline gas supply in combination with

increased industrial activity at Houston

could drop the price to $12.04, while a

wellhead supply with increased industrial

activity could drop the price to $10.96.

And rather than assume a single price

model for the entire period that the

Houston plant would be in operation, there

would likely be opportunities to progres-

sively bring the costs down as, for exam-

ple, further industrial development takes

place or the gas supply opportunities

change, Laurel told the board.

The pricing includes an assumed cost

for the transportation of LNG by railroad

from Houston to Fairbanks. However, a

determination of the burner-tip price of gas

for Fairbanks consumers would require the

inclusion of LNG storage and gas distribu-

tion costs in Fairbanks.

Modular designThe LNG plant would be constructed

using a modular Siemens design that can

be scaled up in increments to meet climb-

ing LNG demand. An initial plant could be

shipped and assembled for operation with-

in 12 months of a contract with IGU being

signed. And the contract would include a

not-to-exceed cost that would eliminate

IGU’s exposure to construction cost over-

run risk, the proposal says.

In terms of security of supply, the pro-

posal says that the potential Houston LNG

plant would have the capability to load

LNG into LNG trucks for transportation to

Fairbanks by road, should some problem

arise with the use of the railroad.

Moreover, the efficient shuttling of LNG

containers on the railroad requires more

containers than are actually in use at any

specific time — the excess containers in

Houston, coupled with LNG storage capa-

bilities there, could provide contingency

storage of up to 720,000 gallons, to back

up the storage that IGU will have available

in Fairbanks.

Knik Tribe and Siemens have suggested

a program of negotiations that they think

could lead to the signing of a contract by

the end of this year. That could lead to the

LNG plant going into operation at the

beginning of 2020. IGU board members

indicated that they want to conduct a side-

by-side comparison of the two LNG

expansion concepts, the Titan expansion

and the Siemens option, to be able to make

a considered decision on which option to

choose. In addition, AIDEA, as financier

for IGU’s LNG expansion project, would

need to be involved in any decision.

—ALAN BAILEY

PETROLEUM NEWS • WEEK OF SEPTEMBER 2, 2018 11

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continued from page 1

LNG PROPOSALIGU board members indicated thatthey want to conduct a side-by-side

comparison of the two LNGexpansion concepts, the Titan

expansion and the Siemens option,to be able to make a considered

decision on which option to choose.

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350,000 acres is close to existing infra-

structure and to the trans-Alaska oil

pipeline and approximately 20 miles

southeast of Deadhorse, which is an unin-

corporated community consisting mainly

of facilities for oilfield workers and firms

that have contracts with the nearby oil

fields, including Prudhoe. Deadhorse is

accessible via the Dalton Highway and

the Deadhorse Airport.

To the west of Prudhoe Bay, Eni owns

and operates the Nikaitchuq oil field and

is a minority owner in the adjacent

Caelus-operated Oooguruk oil field, with

a total net production of approximately

20,000 barrels of oil equivalent a day.

Oooguruk is adjacent to the Pikka unit

where the huge Pikka and Horseshoe oil

discoveries were made in 2016 by

Armstrong and Repsol and are under

plans for development by their partner Oil

Search.

Multiple play types revealed on seismic

Shortly after acquiring the eastern

North Slope leases in 2015, which are in

two blocks, Caelus acquired 175 square

miles of new 3-D seismic data and

reprocessed another 275 square miles of

existing 3-D to image prospects on the

acreage.

“Adjacent infrastructure with available

capacity reduces threshold volumes

required for developing discoveries in the

sub-100 MMBO recoverable range,”

Caelus said. “Multiple play types within

proven stratigraphic horizons provide sig-

nificant upside potential in previously

poorly-imaged structural trends and/or

subtle stratigraphic traps.”

Surrounding legacy wells “confirm

deeper petroleum system elements and

de-risked shallower Brookian reservoirs

and hydrocarbon charge and phase within

the area,” Caelus said, much of which has

been previously reported in PN.

Nikaitchuq North wildcat and unit drilling

Eni’s plan to resume oil drilling at

Nikaitchuq and indications of positive

results from the company’s Nikaitchuq

North wildcat well preceded Eni’s Aug.

29 announcement.

Eni CEO Claudio Descalzi said at a

recent 2018-21 strategy meeting that the

company was “doing well” in Alaska and

had plans for “increased investment” in

the state (see Oil Patch Insider, April 22

issue of PN).

In its 11th plan of development for the

Nikaitchuq unit, Eni announced plans to

drill as many as three new wells and to

add laterals to as many as eight existing

single lateral wells at its Spy Island

Drillsite as soon as October, depending

on “the results and scope of exploration

work” at Nikaitchuq North, which

involved drilling an ultra-extended reach

well from the Spy Island Drillsite into

federal waters north of the Nikaitchuq

unit.

The rig that was used for the wildcat,

Doyon 15, required considerable modifi-

cation and will also be used for drilling

the unit wells.

From the beginning, the purpose of the

wildcat was to add reserves to Nikaitchuq

and to increase production from the unit. l

Note: For more information on Eni’splan of development see this article in theJuly 29 issue of PN: “Eni says drilling atNikaitchuq could resume as early as thisfall.”

continued from page 1

ENI ACQUISITION

linked to exercising the option and undertaking joint divest-

ment.

The company has an option, good through next June, to

acquire the other 50 percent of Armstrong equity in the proj-

ect.

A ‘world-class team’Botten said building a world-class team in Alaska was

critical to the company’s success, with some 50 people

working in Anchorage, a number expected to grow to about

100 by year-end.

In an overhead prepared for the presentation Oil Search

said it is investing in local talent in Alaska, with 70 percent

of its employees residents of Alaska and 9 percent Alaska

Natives.

The company said the team has strong Alaska and inter-

national capability, with the overhead noting 335-plus years

of U.S. oil and gas experience, 240-plus years of Alaska

North Slope experience and extensive global experience.

Oil Search highlighted the diversity of its Alaska team:

28 percent of the leadership team is composed of women;

30 percent of the Oil Search Alaska team are women; and

16 percent are expats transferring Oil Search knowledge to

Oil Search Alaska.

—KRISTEN NELSON

continued from page 8

OIL SEARCHBotten said building a world-class team in

Alaska was critical to the company’s success, withsome 50 people working in Anchorage, a number

expected to grow to about 100 by year-end.