The Explorers, an annual publication from Petroleum News

ExplorersThe

Oil & gas companies

investing in Alaska’s future

ExplorersOil & gas

companies investing in

Alaska’s future

Fate of Eni’s first Slope wildcatin 11 years remains hush-hush

page6

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

l U T I L I T I E S

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

Vol. 24, No. 14 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of April 7, 2019 • $2.50

Oil & Gas DirectoryCovering Arctic oil and gas operations

and the logistics, construction and service firms that support them

Vol. 24, No.1March 2019

ArcticArcticLatest Arctic Directory released

Report indicates ANWR well unlikelyto have found significant crude oil

A report in the New York Times has indicated that the infa-

mous KIC No. 1 well, the only oil exploration well ever to be

drilled in the coastal plain of the Arctic National Wildlife Refuge,

failed to make a significant oil discovery. Chevron and BP drilled

the well in 1985 and 1986; since when the results of the drilling

have remained a closely guarded secret.

Reporters from the New York Times discovered intriguing

evidence relating to a 1987 lawsuit in Cleveland, Ohio, indicating

see KIC WELL page 12

North Slope crude tops $70On April 1, the closing price for Alaska North Slope crude

climbed above $70 for the first time since Nov. 8, 2018, after

a nine and a half month run during which ANS crude was in

the $70s to mid-$80s.

These were the highest prices seen since 2014 after crude

started its multi-year crash below the $100 level, eventually

declining to the low $30s for ANS.

On April Fool’s Day, ANS crude jumped $1.46 to $70.27,

while Brent crude rose 62 cents to $69.01 and West Texas

Intermediate increased $1.45 to $61.59.

ANS crude tends to track close to the international bench-

see OIL PRICES page 11

Canada’s Arctic stirs: offshore activities ban ends term in 2021

To all intents petroleum activity in Canada’s Arctic slipped qui-

etly into a deep and indefinite sleep in 2016.

That was when the government of Prime Minister Justin

Trudeau imposed a moratorium on approved offshore activities,

along with repaying the balance of any final deposits by explo-

ration permit holders and suspending any oil and gas activities for

the duration of a five-year moratorium ending in 2021.

The government also agreed to work with the Northwest

Territories, Yukon and Nunavut, indigenous communities and the

see ARCTIC STIRS page 10

Arctic OCS is outJudge rules as illegal Trump order canceling Obama leasing withdrawal

By ALAN BAILEYPetroleum News

In a March 29 order Judge Sharon Gleason from

the federal District Court in Alaska ruled as

unlawful an April 2017 executive order by President

Donald Trump, canceling an order issued in 2016 by

President Barack Obama that designated much of the

outer continental shelf of the Chukchi and Beaufort

seas as indefinitely off limits to oil and gas leasing.

Gleason ruled that only an act of Congress can over-

turn the 2016 order.

Gleason’s ruling is the outcome of a District

Court appeal launched by a group of environmental

organizations, challenging the validity of Trump’s

reversal of the land withdrawal.

Lease sale plansSince that reversal, the Bureau of Ocean Energy

Management has been pursuing a plan to conduct oil

and gas lease sales in the Beaufort Sea. Currently an

environmental impact statement is being prepared

for a lease sale this year, potentially spanning the

Deal goes to RCAChugach Electric applies to commission for approval for purchase of ML&P

By ALAN BAILEYPetroleum News

On April 2 Anchorage electric utility Chugach

Electric Association filed a request with the

Regulatory Commission of Alaska for approval of

the acquisition by Chugach Electric of Municipal

Light & Power. ML&P is owned by the

Municipality of Anchorage and provides electrici-

ty to customers in central Anchorage. Chugach

Electric’s service territory includes those parts of

Anchorage not served by ML&P.

The idea behind the acquisition is to reduce the

long-term cost of energy for consumers by means

of economies of scale and improved efficiency

achievable through utility consolidation. In April

2018 Anchorage voters gave the municipality

authority to sell ML&P. Since then the two utilities

have been working out the details of the deal, in

preparation for the RCA filing.

“After thousands of hours of thought, analysis,

and negotiations, we are very pleased to reach this

milestone,” said Chugach Electric CEO Lee

Hope for embattled linesTrump issues new presidential approval for Keystone XL; green light for Line 3

By GARY PARKFor Petroleum News

Another day another twist in Canada’s tangled

pipeline tale.

Only this time, when proponents of those working

to build new export links for oil sands bitumen seem

to face endless adversity, there was a shred of hope in

the news.

Leading the way was President Donald Trump,

who unexpectedly issued a new permit for

TransCanada’s Keystone XL line.

It was accompanied by confirmation from the

Minnesota Public Utilities Commission of its ear-

lier approval for Enbridge’s plan to replace its Line

3 system.

Out of the White House came word that Trump

had decided to undercut legal challenges to the US$8

billion XL project he had already endorsed in March

2017 after President Barack Obama denied a permit

on grounds that the bitumen shipments of 800,000

barrels per day to Gulf Coast refineries would con-

see ARCTIC OCS page 12

see ML&P DEAL page 11

see PIPELINE HOPE page 10

Gleason also supported a view that, hadCongress intended that a president should

have the authority to revoke awithdrawal, Congress would have

explicitly stated this in the act.

The idea behind the acquisition is toreduce the long-term cost of energy for

consumers by means of economies of scaleand improved efficiency achievable

through utility consolidation.

Unlike an earlier State Departmentpermit, which was issued after an

extensive environmental analysis requiredunder the National Environmental Policy

Act, the new presidential permit is notdirectly tied to any such review.

2 PETROLEUM NEWS • WEEK OF APRIL 7, 2019

GOVERNMENT

UTILITIES

EXPLORATION & PRODUCTION

FINANCE & ECONOMY

PIPELINES & DOWNSTREAM

5 February ANS crude down 1.8% from January

7 State approves CINGSA’s plan for 2019

8 Tariff increase posted for Alpine Pipeline

8 US drilling rig count drops by 10 to 1,006

8 AOGCC changes well integrity order

9 BP plans more Prudhoe drilling in IPA

10 CIRI increases its ownership in CINGSA

2 Pantheon confirms oilfield discovery

New Brookian oil pool penetrated by Alkaid well is atconvenient location near Dalton Highway and TAPS south of Prudhoe Bay

8 Renewable energy projects not approved

RCA: Two programs proposed by Chugach Electric areinadequately defined, include some unacceptable uncertainties

6 Wildcats in Eni’s North Slope future?

As CEO talks about increased worldwide exploration, includingin Alaska, fate of first NS wildcat in years remains hush-hush

4 RCA reviews power generation efficiency

Assesses data provided by utilities on energy sales betweeneach other to enable use of most energy efficient facilities

ALTERNATIVE ENERGY

EXPLORERS PREVIEW

Arctic OCS is outJudge rules as illegal Trump order canceling leasing withdrawal

Deal goes to RCA Chugach Electric applies for approval for purchase of ML&P

Hope for embattled linesTrump issues new presidential OK for Keystone XL; Line 3 green light

ON THE COVER

Report indicates ANWR well unlikelyto have found significant crude oil

North Slope crude tops $70

Canada’s Arctic stirs: offshoreactivities ban ends term in 2021

Petroleum News Alaska’s source for oil and gas newscontents

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

Pantheon confirms oilfield discoveryNew Brookian oil pool penetrated by Alkaid well is at convenient location near Dalton Highway and TAPS south of Prudhoe Bay

By ALAN BAILEYPetroleum News

In an April 2 news release Pantheon Resources com-

mented that flow testing in the Alkaid No. 1 well has

confirmed a new oil field discovery, just west of the

Dalton Highway, south of the Prudhoe Bay unit. The

company is applying to the state for permission to sus-

pend and freeze protect the well, for future use in a field

development. Moreover, the company now views anoth-

er potential nearby drilling project, into what is called

the Phecda prospect, as an appraisal well for the Alkaid

discovery, rather than a standalone exploration well.

Pantheon says that the proximity of the new find to

the Dalton Highway and the trans-Alaska pipeline

should enable a shorter permitting and development

schedule than is typical for the North Slope.

As previously reported in Petroleum News, Pantheon

has confirmed the successful flow testing of the oil dis-

covery in the Brookian sequence in the Alkaid well. The

test flowed 80 to 100 barrels of 40 API oil per day from

a vertical perforated interval through the reservoir —

horizontal wells that would be used in a field develop-

ment would enable much higher flow rates, the company

said. The zone of interest in the Brookian is estimated to

have 240 feet of net pay within 400 feet of reservoir

rock.

Testing of secondary targets at shallower depths

proved less successful, with brackish water being found

in the West Sak and also inferred to be present in the

Ugnu.

Drilled in 2015Great Bear Petroleum drilled the Alkaid well in 2015

as a vertical test well but was unable to conduct flow

testing in the well because the drilling program was cut

short by flooding on the Dalton Highway. The company

had previously carried out an extensive program of 3-D

seismic surveying in its acreage and had identified sev-

eral oil prospects, including the Alkaid. The subsequent

suspension of payments of state exploration tax credits

under the administration of former Gov. Bill Walker

resulted in a pause in Great Bear’s exploration program.

Meanwhile the Alkaid well was suspended until such

time as that testing could be done.

London-based Pantheon Resources acquired the

assets of Great Bear Petroleum in January of this year,

with the consequence, in effect, of merging the two com-

panies. Pantheon subsequently elected to proceed with

the Alkaid well testing.

Phecda prospectPantheon now says that the positive result from the

Alkaid well, together with data from Great Bear’s 3-D

seismic, has “positive implications” for the Phecda

see ALKAID DISCOVERY page 7

PETROLEUM NEWS • WEEK OF APRIL 7, 2019 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, MPU M-11 Hilcorp Dreco 1000 UE 16 (SCR/TD) Standby Dreco D2000 Uebd 19 (SCR/TD) GTMU, demobilizing ConocoPhillipsAC Mobile 25 Alpine CD2-162 ConocoPhillipsOIME 2000 141 (SCR/TD) West Willow 2, Exploratory ConocoPhillips 142 (SCR/TD) Tinmiaq 13, Exploratory ConocoPhillips TSM 700 Arctic Fox #1 Pikka B Oil Search

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

Kuukpik Drilling 5 Deadhorse Available

Nabors Alaska DrillingAC Coil Hybrid CDR-2 (CTD) Deadhorse L2-07B BPAC Coil CDR-3 (CTD) Kuparuk 1C-11 ConocoPhillipsDreco 1000 UE 7-ES (SCR-TD) Kuparuk 2K-26 ConocoPhillipsMid-Continental U36A 3-S Stacked AvailableOilwell 700 E 4-ES (SCR) Stacked AvailableDreco 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) Pikka C ST1 Oil Search Academy AC electric Heli-Rig 106AC (AC-TD) Stacked Great Bear Petroleum

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

Parker Drilling Arctic Operating LLC NOV ADS-10SD 272 Prudhoe Bay NK-08 BPNOV ADS-10SD 273 Stacked in Deadhorse Available

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) Oooguruk 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 North Slope stacked Available

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

Hilcorp Alaska LLCTSM-850 147 Stacked Hilcorp Alaska LLCTSM-850 169 Seaview 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 A-13, stacked Hilcorp Alaska LLC Spartan Drilling Baker Marine ILC-Skidoff, jack-up Spartan 151, Moored in Kenai

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

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 April 3, 2019.

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* March 29 March 22 Year AgoUnited States 1,006 1,016 993Canada 88 105 134Gulf of Mexico 23 20 12

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

The Alaska - Mackenzie Rig Report is sponsored by:

JUDY

PAT

RICK

By ALAN BAILEYPetroleum News

During a March 27 meeting of the

Regulatory Commission of Alaska

the commissioners heard and discussed a

staff presentation on data relating to ener-

gy sales between the six Alaska Railbelt

electric utilities. The utilities participate in

what are referred to as economy energy

sales, selling power to each other, to make

use of efficient power generation while

also ensuring that their power supply

requirements can be continuously met.

The presentation came in the context

of the RCA’s desire that the utilities

implement merit ordered economic dis-

patch, a procedure whereby the utilities

would pool their generation facilities and

continuously use the most efficient avail-

able units. The idea is to minimize the

generation costs that are passed onto elec-

tricity consumers. This is one of several

initiatives that the RCA is facilitating

toward a more unified approach to the

operation of the Railbelt electrical sys-

tem.

Evolving situationIn 2017 the three Southcentral Alaska

utilities — Chugach Electric Association,

Municipal Light & Power and Matanuska

Electric Association — announced an

agreement to implement economic dis-

patch across their service areas. The utili-

ties developed protocols for the imple-

mentation and conducted some testing of

the arrangements. However, all of this

came to a halt in 2018 after Chugach

Electric embarked on a project involving

the purchase of ML&P. Chugach Electric

said it was not realistic to try to proceed

with the economic dispatch initiative in

parallel with dealing with the complica-

tions of the ML&P purchase. Moreover,

Chugach Electric has said that its merger

with ML&P would, in effect, enable eco-

nomic dispatch across those two utilities’

service areas. During the March 27 meet-

ing, Tony Izzo, CEO of Matanuska

Electric Association, commented that

MEA stands ready to recommence the

economic dispatch project, once it

becomes possible to proceed again.

The RCA commissioners have

expressed their frustration with the hiatus

in the economic dispatch progress. They

ordered the utilities to provide data relat-

ing to economy energy sales, to enable an

assessment of the extent to which these

sales are moving the energy efficiency

pendulum towards the economic dispatch

model.

More sales, lower pricesJames Layne, RCA utility engineering

analyst, told the commissioners that the

data indicates that, excluding the impact

of the startup of Golden Valley Electric

Association’s Healy 2 coal fired power

station in the third quarter of 2018, the

amount of energy transacted through

economy energy sales had increased from

12.5 percent to 15 percent between 2017

and 2018. At the same time, the price paid

for this energy tended to decrease.

Layne also commented that the Healy

2 startup had caused a significant change

in the pattern of economy energy sales:

GVEA’s purchase of power from other

utilities had dropped to almost zero fol-

lowing the startup.

Also of interest is the heat rate of the

power generation used. The heat rate is a

measure of the amount of energy used to

generate power, relative to the energy in

the generated electricity: the lower the

heat rate, the more efficient the genera-

tion. The data show that the average heat

rate of power generation used in the

Railbelt dropped slightly between 2017

and 2018, an indication that the utilities

are working together to generate power

with the most efficient units available.

One anomaly in this picture is the third

quarter of 2018, when Healy 2 came on

line. Healy 2, with a relatively high heat

rate, reduced the overall power genera-

tion efficiency in that quarter.

Capacity usageLayne also presented data showing the

extent to which the available capacity

was used from the two most efficient gas-

fired power plants on the grid: the

Southcentral Power Project and ML&P’s

Plant 2A. There is no obvious pattern in

this data, and the capacity factors varied

greatly between percentages in the 60s

and percentages in the high 80s.

Intuitively, these factors should be overall

higher in an economic dispatch arrange-

ment, but it would be difficult to say what

to expect without running models of the

economic dispatch system, Layne com-

mented.

Another issue is the sale and purchase

of spin capacity, the capacity that is avail-

able as backup, should planned genera-

tion not be available. There were many

fewer spin transactions in 2018 than in

2017, and the majority of those transac-

tions in 2017 were between GVEA and

MEA. Ed Jenkin, director of power deliv-

ery for MEA, explained that this apparent

anomaly resulted from the manner with

which MEA purchases power from

ML&P — the purchase of power from

ML&P can enable MEA to take a genera-

tion unit offline, thus making that unit

available for spin capacity.

One oddity in the data is an observa-

tion that during three months MEA pur-

chased power from ML&P while also

selling power to Chugach Electric at a

higher price. This appears to have been a

result of factors such as the availability of

specific power generation facilities.

Increased cooperationCommissioner Anthony Scott com-

mented that the data suggest that there

has been an increase in cooperation

between the utilities in using the most

efficient power generation. But, while

some aspects of the data are reassuring,

there is still concern about the situation

regarding economic dispatch implemen-

tation. Scott proposed a motion to require

the continuation of collection of the

power generation data on a quarterly

basis, and to publish the continuing

results of analyzing this data. The motion

was carried. l

l U T I L I T I E S

RCA reviews power generation efficiencyAssesses data provided by utilities on economy energy sales between each other to enable use of most energy efficient facilities

4 PETROLEUM NEWS • WEEK OF APRIL 7, 2019

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In 2017 the three SouthcentralAlaska utilities — Chugach

Electric Association, MunicipalLight & Power and Matanuska

Electric Association — announcedan agreement to implement

economic dispatch across theirservice areas.

By KRISTEN NELSONPetroleum News

A laska North Slope production aver-

aged 527,644 barrels per day in

February, down 1.8 percent, 9,850 bpd,

from a January average of 537,493 bpd.

Of the February total, 472,457 bpd, 89.5

percent, was crude oil; 55,187 bpd, 10.5

percent, was natural gas liquids, with the

majority of the NGLs coming from the

Prudhoe Bay field.

February’s volumes were down 4.1

percent from a February 2018 average of

550,019 bpd.

Production data reported here is from

the Alaska Oil and Gas Conservation

Commission, which provides volumes by

field and well on a month-delay basis.

Increases at three fieldsThe largest month-over-month pro-

duction increase was at the

ConocoPhillips Alaska-operated Kuparuk

River field, second largest on the Slope,

which averaged 107,582 bpd in February,

up 1.5 percent, 1,597 bpd, from a January

average of 105,984 bpd, but down 8.9

percent from a February 2018 average of

118,104 bpd. In addition to the main

Kuparuk pool, Kuparuk produces from

satellites at Meltwater, Tabasco and Tarn,

and from West Sak.

The largest percentage increase was at

ConocoPhillips’s Greater Mooses Tooth

in the National Petroleum Reserve-

Alaska, which averaged 12,526 bpd in

February, up 3.7 percent, 449 bpd, from a

January average of 12,077 bpd. That field

came online in October; in February it

was producing from two wells.

The other North Slope field with a

month-over-month production increase

was the Hilcorp Alaska-operated Milne

Point field, which averaged 23,108 bpd in

February, up 3.2 percent, 723 bpd, from a

January average of 22,385. Milne produc-

tion was also up year-over-year, an

increase of 11.4 percent from a February

2018 average of 20,753 bpd.

Largest drops at Prudhoe, BadamiThe largest declines were at the

Slope’s largest and smallest fields —

Prudhoe and Badami.

The largest month-over-month decline

by volume, 9,281 bpd, was at the BP

Exploration (Alaska)-operated Prudhoe

Bay field, the Slope’s largest, which aver-

aged 275,307 bpd in February, 224,196

bpd of crude and 51,111 bpd of NGLs.

Month-over-month production was down

3.3 percent from a January average of

284,588 bpd and down 5.2 percent from a

February 2018 average of 290,376 bpd.

In addition to the primary reservoir,

production volumes from Prudhoe

include Aurora, Borealis, Lisburne,

Midnight Sun, Niakuk, Polaris, Point

McIntyre, Put River, Raven and Schrader

Bluff.

The largest month-over-month percent

decrease was at the Badami field, current-

ly the Slope’s smallest, operated by

Glacier Oil & Gas subsidiary Savant,

which averaged 1,823 bpd in February,

down 21.5 percent, 500 bpd, from a

January average of 2,323 bpd. Production

at the field was, however, up 174.2 per-

cent from a February 2018 average of 665

bpd. Production at Badami increased sub-

stantially in May of 2018 when Savant

brought the B1-07 well online, almost

doubling production from 698 bpd in

April 2018 to 1,329 bpd. Production has

fluctuated since, topping out (for recent

production years) at 2,323 bpd this

January. (When BP brought Badami

online in the late 1990s the company

expected production volumes of 10,000

bpd; it shut the field in to protect the

pipeline when production dropped to less

than 3,000 bpd; the Badami pipeline cur-

rently carries Point Thomson condensate

as well as Badami crude.)

Others down month-over-monthThe ExxonMobil Production-operated

Point Thomson field averaged 8,784 bpd

in February, down 7.4 percent, 705 bpd,

from a January average of 9,490 bpd, but

up 57.1 percent from a February 2018

average of 5,592 bpd. The field came

online in April 2016, producing conden-

sate and reinjecting natural gas. It was

offline for much of this last summer for

maintenance and resumed operation in

October, with production increasing to a

December peak of 10,725 bpd. Point

Thomson facilities were designed to pro-

duce 10,000 bpd of condensate.

Eni’s Nikaitchuq averaged 17,244 bpd

in February, down 6.2 percent, 1,311 bpd,

from a January average of 18,375, and

down 11.1 percent from a February 2018

average of 19,403 bpd.

The Hilcorp Alaska-operated

Northstar field averaged 11,553 bpd in

February, down 2.8 percent, 336 bpd,

from a January average of 11,890 bpd,

but up 10.9 percent from a February 2018

average of 10,418 bpd. Northstar’s

February production included 8,496 bpd

of crude oil and 3,057 bpd of NGLs.

Eni took over the Oooguruk field in

January (it had previously been a minori-

ty working interest owner) and that field

averaged 9,155 bpd in February, down

1.9 percent, 182 bpd, from a January

average of 9,336, and down 31.6 percent

from a February 2018 average of 13,385

bpd.

ConocoPhillips’ Colville River field

averaged 53,053 bpd in February, down

0.9 percent, 474 bpd, from a January

average of 53,527 bpd, and down 16.7

percent from a February 2018 average of

63,690 bpd. In addition to oil from the

main Alpine pool, Colville production

includes satellite production from Fiord,

Nanuq and Qannik.

The Hilcorp-operated Endicott field

averaged 7,508 bpd in February, down

0.1 percent, 11 bpd, from a January aver-

age of 7,518 bpd and down 1.6 percent

from a February 2018 average of 7,633

bpd. Endicott’s February production

included 6,489 bpd of crude and 1,019

bpd of NGLs.

Cook Inlet up marginallyCook Inlet crude oil production aver-

aged 15,134 bpd in February, up 0.6 per-

cent, 86 bpd, from a January average of

15,048 bpd, but down 6.3 percent from a

February 2018 average of 16,146 bpd.

Most fields saw a month-over-month

decline in production, with the exception

of fairly solid month-over-month increas-

es at the Redoubt Shoal and West

McArthur River fields, both operated by

Glacier Oil & Gas subsidiary Cook Inlet

Energy, and a marginal gain at Hilcorp

Alaska’s Swanson River field.

Hilcorp Alaska’s Beaver Creek field,

Cook Inlet’s smallest, averaged 346 bpd

in February, down 28.2 percent, 136 bpd,

from a January average of 482 bpd, but

up 226 percent from February 2018,

when the field averaged 106 bpd.

Production at the field kicked up in

November from fewer than 100 bpd to

904 bpd following a redrill, with the

5RD2 well accounting for the sudden

increase. Production has declined each

month since November.

Hilcorp’s Granite Point averaged

2,624 bpd in February, down 1.9 percent,

50 bpd, from a January average of 2,674

bpd and down 7.1 percent from February

2018, when the field averaged 2,823 bpd.

BlueCrest’s Hansen field, the

Cosmopolitan project, averaged 1,396

bpd in February, down 2 percent, 29 bpd,

from a January average of 1,425 bpd but

up 78.5 percent from February 2018

when it averaged 782 bpd.

Hilcorp’s McArthur River field, Cook

Inlet’s largest, averaged 4,810 bpd in

February, down 6.6 percent, 341 bpd,

from a January average of 5,151 bpd, and

down 2.4 percent from a February 2018

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

February ANS crude down 1.8% from JanuaryNorth Slope production averaged 472,457 bpd of crude oil, 55,187 bpd of NGLs; Cook Inlet up marginally at an average of 15,134 bpd

PETROLEUM NEWS • WEEK OF APRIL 7, 2019 5

(907) 562-5303 | akfrontier.com

Safety Health Environment Quality

THE TEAM THAT

DELIVERS

The largest declines were at whatare the Slope’s largest and smallest

fields — Prudhoe and Badami.

see PRODUCTION REPORT page 7

6 PETROLEUM NEWS • WEEK OF APRIL 7, 2019

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By KAY CASHMANPetroleum News

A fter an 11-year hiatus Eni US

Operating Co. returned to Alaska

exploration in late December 2017 with

the spudding of the first of two ultra-

extended reach wells from a manmade

Beaufort Sea island in the Nikaitchuq unit.

The prospect is adjacent to, and directly

north of, the Nikaitchuq unit.

The exploration program was expected

to take two years. Due to a series of

delays, as of early

April 2019, the mod-

ified Doyon 15

drilling rig was still

on the Nikaitchuq

North No. 1 explo-

ration well, or NN-

01, with no more

than hints from Eni

on well results, start-

ing with a May 2018

strategy meeting

where Eni CEO Claudio Descalzi said the

company was doing well in Alaska and

planned to increase investment in the

state.

No permit for a second well was filed

with the Alaska Oil and Gas Conservation

Commission, per its website, and no

AOGCC update was available for the NN-

01 well, which is listed as confidential.

The current plan approved by the state

of Alaska and the federal Bureau of Ocean

Energy Management said the drilling of

the second exploration well, NN-02, “tar-

geting the same seismic anomaly of the

first well” was contingent upon NN-01

results.

The nearshore Nikaitchuq unit, which

began producing oil in early 2011, lies

north of the Kuparuk River unit, west of

Prudhoe Bay, and northeast of the adjacent

Oooguruk unit.

The Alaska subsidiary of the Milan,

Italy-based major is looking for new oil

reserves at Nikaitchuq North to take

advantage of significant spare capacity in

the standalone Nikaitchuq production

facilities, which in late 2017 handled some

20,000 barrels of oil per day but had a

capacity of 40,000 bpd and could be

expanded to 50,000 bpd, according to Eni

Alaska Vice President Whitney Grande.

Geological target speculationThe “seismic anomaly” from 3-D over

Nikaitchuq North that was noted in the

approved plan did not identify the target of

the exploration program, but the Schrader

Bluff formation that is produced from the

Nikaitchuq unit is known to extend a long

way north under the Beaufort Sea.

The previous unit operator, Kerr-

McGee, also talked about the possibility

of testing the Jurassic Nuiqsut sandstone

and the Triassic Sag River sandstone to the

north.

They said exploration and development

drilling in the area of the Nikaitchuq unit

“establishes an overall prospective trend

for improved Sag River sand quality and

thickness to the north/northwest over the

northwest Milne structure and within our

proposed Nikaitchuq exploration unit.”

Federal block 50 percent owned by Shell

Although Eni spud the NN-01 well in

late 2017, drilling did not get underway

until February 2018 because of what the

company said were “unforeseen impacts

to the drilling schedule.”

According to the published plan, the

well was to have a vertical depth of 8,131

feet and a measured depth of 34,150 feet,

although more recently company officials

talked in terms of 35,000 feet for the

measured depth: “It will be the longest

extended reach well in the state,” stretch-

ing into federal Beaufort Sea waters,

specifically Harrison Bay Block 6423,

which is 50 percent owned by Shell,

Grande said in November 2017.

Eni’s initial plan was to complete the

Nikaitchuq North prospect well in mid-

February 2018, potentially conducting

flow testing between mid-February and

mid-March, but completion of the well

was deferred to mid-summer. But later

that year an Eni official told Petroleum

News, “the NN-01 exploration well was

not completed in 2018 and as such no flow

test was performed. Drilling was suspend-

ed on Aug. 23 due to impending seasonal

drilling restrictions. Eni intends to restart

drilling in early 2019.”

No exploration reservoir targets are

allowed to be drilled during broken ice

seasons, per Alaska’s Division of Oil and

Gas. Drilling can only take place during

frozen ice conditions and during the sum-

mer open water season.

Adds production by Oooguruk acquisition

Eni, which was the fourth largest oil

producer in Alaska in 2018, behind

ConocoPhillips, BP and Hilcorp, at the

end of that year held a working interest in

two producing North Slope fields. It had a

100 percent interest in, and was operator

of, the Nikaitchuq unit and was a 30 per-

cent partner in Caelus Natural Resources

Alaska’s nearby Oooguruk unit, which is

adjacent to the Pikka unit where the huge

Brookian Nanushuk oil discoveries were

made in the last few years by Armstrong

and Repsol. The first Pikka development

is slated to go online in 2023 under the

operatorship of their partner Oil Search.

In January 2019, Eni said it had entered

into an agreement with Caelus to acquire

70 percent and operatorship of Oooguruk.

The deal gave Eni approximately 7,000

barrels of oil per day and allowed it to

“implement important operational syner-

gies and optimizations” with nearby

Nikaitchuq, which at the time produced

18,000 bpd.

In January 2019, the Oooguruk field

averaged 9,336 bpd, down 5.8 percent

from a December average of 9,909 and

down 29.2 percent from a January 2018

average of 13,191 bpd.

Eni said it planned to drill more pro-

duction wells in both units: Caelus drilled

one production well and one injection well

in the Oooguruk field in 2016, but there-

after suspended drilling. In response to the

downturn in oil prices in 2014, Eni con-

ducted minimal drilling in its Nikaitchuq

field from 2015 to fourth quarter 2018.

In January 2019, the largest month-

l E X P L O R E R S P R E V I E W

Wildcats in Eni’s North Slope future?While CEO talks about stepping up worldwide exploration, including in Alaska, fate of first NS wildcat in 11 years remains hush-hush

Coming

The Explorers, an annual publication from Petroleum News

ExplorersThe

Oil & gas companies investing in

Alaska’s future

ExplorersOil & gas

companies investing in

Alaska’s future

May 25, 2019

see EXPLORERS PREVIEW page 7

!

!

!

!

!!

!!

!!!!

!!

!

!!

!

!!!

!!

!

!!!!

!!

!!!

!

!!!!!

!!!!!

! !!

!

Deadhorse

Prudhoe Bay

Milne Point

Duck Island

Liberty

BeecheyPoint

Kuparuk River

Oooguruk

Placer

Prudhoe Bay

Point Thomson

Nikaitchuq

Badami

Guitar

Bear ToothGreaterMoosesTooth

NikaitchuqNorth

Taktuk

Pikka

SouthernMiluveach

Northstar

ColvilleRiver

Trans - Alaska Pipeline

Dalto

n Hw

yska Seaward Boundary

Arctic NationalWildlife Refuge

North Slope oil and gas units.

STA

TE O

F A

LASK

A

PETROLEUM NEWS • WEEK OF APRIL 7, 2019 7

Anchorage Honolulu Los Angeles

• Commercial Diving• Marine Construction Services• Platform Installation, Maintenance and Repair• Pipeline Installation, Maintenance and Repair• Underwater Certified Welding• NDT Services• Salvage Operations• Vessel Support and Operations

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Maintenance, Management, and Operations

American MarineServices Group

6000 A Street, Anchorage, AK 99518

907-562-5420Deadhorse, AK

907-659-9010www.amarinecorp.com • www.penco.org

alaska@amarinecorp.com

average of 4,926 bpd.

Middle Ground Shoal, also operated

by Hilcorp, averaged 1,422 bpd, down

1.9 percent, 27 bpd, from a January

average of 1,449 bpd and down 7.5 per-

cent from a February 2018 average of

1,537 bpd.

Redoubt, operated by Glacier Oil &

Gas subsidiary Cook Inlet Energy,

averaged 1,496 bpd in February, up

52.5 percent, 515 bpd, from a January

average of 981 bpd and up 2 percent

from a February 2018 average of 1,467

bpd. Over the last year production at

the field has fluctuated but has general-

ly remained in the range of 1,200 to

1,350 bpd with the exception of

January.

Hilcorp’s Swanson River field had a

slight increase in February, averaging

1,063 bpd, up 0.9 percent, 9 bpd, from

a January average of 1,053 bpd, but

was down 31.4 percent from a

February 2018 average of 1,548 bpd.

Hilcorp’s Trading Bay field aver-

aged 1,287 bpd in February, down 6.9

percent, 95 bpd, from a January aver-

age of 1,382 bpd, and down 29.8 per-

cent from a February 2018 average of

1,833 bpd.

West McArthur River, like Redoubt

operated by Glacier Oil & Gas sub-

sidiary Cook Inlet Energy, averaged

690 bpd in February up 53 percent, 239

bpd, from a January average of 451

bpd, but down 38.6 percent from a

February 2018 average of 1,124 bpd.

Redoubt production has been in decline

for the past two months.

ANS crude oil production peaked in

1988 at 2.1 million bpd; Cook Inlet

crude oil production peaked in 1970 at

more than 227,000 bpd. l

continued from page 5

PRODUCTION REPORT

prospect — Great Bear had identified

Phecda as a potential drilling target.

Pantheon has now upgraded Phecda and

views this prospect as a step out appraisal

for the Alkaid discovery, the company

said.

“These two projects will now likely be

part of a single development plan, favor-

ably located adjacent to the Dalton

Highway and TAPS pipeline,” Pantheon

said. “The better than expected results in

the zone of interest will also impact the

pre-drill P50 technically recoverable

resource estimates which will be assessed

in the near future.”

Pantheon holds a 100 percent interest

in the production testing operations. Joint

venture partner Halliburton would kick in

with a 25 percent share in the event of a

plug and abandon operation, with

Halliburton also having the right to buy

pack into a 25 percent working interest in

the prospect. l

continued from page 2

ALKAID DISCOVERY

PIPELINES & DOWNSTREAMState approves CINGSA’s plan for 2019

Alaska’s Division of Oil and Gas has approved Cook Inlet Natural Gas Storage

Alaska’s plan of development for 2019. The plan anticipates carrying out of main-

tenance and some small projects at the facility, south of the city of Kenai on the

Kenai Peninsula. In an earlier version of the plan, CINGSA had anticipated con-

ducting a significant project to add some redundant features to the facility, to mit-

igate the risk of some existing component of the facility failing. However, the

Regulatory Commission of Alaska declined to pre-approve the technical prudence

of the project, thus exposing CINGSA to the risk that it might not be possible to

obtain approval to recover the project cost through the rates that it charges its cus-

tomers.

The facility provides a vital service to power and electric utilities in

Southcentral Alaska by enabling the utilities to warehouse gas when gas produc-

tion exceeds demand, thus making stored gas available for use when gas demand

peaks. CINGSA enjoys a strong reputation for the reliability of its services and the

RCA was not convinced that the company had provided compelling reasons for

conducting the upgrade project.

According to the approved plan of development, CINGSA injected 6.1 billion

cubic feet of gas into storage and withdrew 4.3 billion cubic feet in 2018. The

company used coiled tubing to clean sand out of one of the facility’s wells, and

perforations were added to the well. Sand monitoring equipment was added to

two other wells. The facility has five wells, all of which can be used to inject gas

into the subsurface storage reservoir or to withdraw gas from the reservoir for

delivery to customers.

—ALAN BAILEY

over-month Alaska production increase

came from Nikaitchuq, which averaged

18,375 bpd, up 99.6 percent from a

December average of 9,205, and down

only 3.9 percent from a January 2018

average of 19,117 bpd. This increase was

a return to a more normal level of produc-

tion at Nikaitchuq, where production hit a

low of 6,553 bpd in November 2018 when

there were only 10 wells operating. By

December, the number of wells producing

crude was back up to 26 (25 in January),

compared to 27 in January 2018.

Buys 350,000 undeveloped acres to east

Going back to 2018, in late August Eni

announced it had acquired 350,000 unde-

veloped exploration acres from Caelus.

The 124 state leases are on the eastern

North Slope between Prudhoe Bay and

Point Thomson.

The company said at the time that it

planned to “apply its business model and

experience,” involving “fast-track explo-

ration” and “a short time to market” for

the “potential new discoveries.”

The relatively unexplored acreage is

close to existing infrastructure and to the

trans-Alaska oil pipeline and approxi-

mately 20 miles southeast of Deadhorse,

which is an unincorporated 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.

Seismic reveals multiple play types 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 in 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 was

mostly ignored in drilling until Armstrong

and Repsol discovered big oil finds in the

shallow Brookian Nanushuk at Pikka and

Horseshoe west of the central North

Slope.

Stepping up explorationTowards the end of first quarter 2019,

Eni said it planned to spend $4 billion on

drilling at least 140 wildcats over the next

four years, targeting 2.5 billion barrels of

potential resources, many in frontier

basins. Descalzi said the company was

looking to Alaska to increase Eni’s oil pro-

duction.

He said the company would drill about

40 wells per year, with an annual outlay of

more than $1 million.

In North America wells are planned in

both Mexico and Alaska.

Eni currently has access to approxi-

mately 177,607 square miles of net explo-

ration acreage, up 37 percent from 2014,

which Descalzi said could hold more than

12 billion barrels of estimated resource

potential. l

continued from page 6

EXPLORERS PREVIEWTowards the end of first quarter

2019, Eni said it planned to spend$4 billion on drilling at least 140wildcats over the next four years,

targeting 2.5 billion barrels ofpotential resources, many in

frontier basins.

8 PETROLEUM NEWS • WEEK OF APRIL 7, 2019

EXPLORATION & PRODUCTIONUS drilling rig count drops by 10 to 1,006

The number of rigs drilling for oil and natural gas in the U.S. dropped by 10 the

week ending March 29 to 1,006.

A year ago the count was 993 active rigs.

Houston oilfield services company Baker Hughes reported that 816 rigs targeted

oil (down eight from the previous week) and 190 targeted natural gas (down two).

The company said 64 of the U.S. holes were directional, 891 were horizontal and

51 were vertical.

Among major oil and gas producing states, Louisiana and North Dakota were

each up by three rigs.

New Mexico, Pennsylvania and Wyoming were unchanged.

Oklahoma was down by one rig.

California was down by two rigs, Alaska was down by three rigs and Colorado

was down by four rigs.

Texas, the most active state with 491 rigs, was down six from the previous week.

Baker Hughes shows Alaska with six active rigs, down three from a count of nine

a year ago.

The U.S. rig count peaked at 4,530 in 1981. It bottomed out in May 2016 at 404.

—PETROLEUM NEWS

AOGCC changes well integrity orderThe Alaska Oil and Gas Conservation Commission has made a change to the

order it issued relating to the mechanical integrity of Prudhoe Bay wells. Following

leakages from two wellheads resulting from permafrost subsidence, the commission

ordered field operator BP to recover casing and tubing from at least two of the wells

that have casing designs associated with the well failures, with further rig interven-

tions needed on other wells identified through negotiations between BP and the

commission.

The idea is to examine and test the tubing and casings, to better understand the

impacts on the wells of the subsidence of surface casings, thus enabling more com-

plete insights into how to prevent similar well failures in the future.

According to an AOGCC order issued on April 1, BP told the commission that it

may not be technically feasible and may present unnecessary risk to fully recover

the well tubing and casings, as required by the commission. Consequently, the

AOGCC has modified its original order, to require the tubing and casing to be

recovered, to the extent approved by AOGCC on a well-by-well basis.

—ALAN BAILEY

GOVERNMENT

PIPELINES & DOWNSTREAMTariff increase posted for Alpine Pipeline

Alpine Transportation Co. has submitted an increase in its Alpine Pipeline tariff

rates to the Regulatory Commission of Alaska, citing lower throughput than projected

when the current rate was established.

The proposal is for an increase to 69 cents per barrel from 41 cents per barrel for

transportation from ConocoPhillips Alaska’s Alpine field to the Kuparuk River unit

and an increase to 20 cents per barrel from 12 cents per barrel for transportation from

the Southern Miluveach unit to the Kuparuk River unit.

Through its attorneys, ATC told RCA that the revised rates were calculated in

accordance with the settlement methodology in the Alpine Settlement Agreement.

That agreement requires ATC to file its rates for the following year by Dec. 1. Current

rates were approved effective Jan. 1 for Alpine to Kuparuk and March 11 for Southern

Miluveach to Kuparuk.

The settlement agreement allows ATC to adjust its rates reflecting new or addition-

al data if that results in an increase or decrease of at least 10 percent.

The revised rates are an increase of some 67 percent, exceeding the 10 percent

threshold, driven primarily by 2019 throughput which is “significantly less than the

projected throughput in the initial calculation,” actual throughput for September to

December of last year (estimated for the proposed 2019 rates) less than projected,

2019 operating expenses greater than projected and operating expenses for September

through December of last year which were greater than projected.

—KRISTEN NELSON

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

Renewable energyprojects not approvedRCA says that two programs proposed by Chugach Electric areinadequately defined and include some unacceptable uncertainties

By ALAN BAILEYPetroleum News

In a March 29 order the Regulatory

Commission of Alaska rejected two

applications by Chugach Electric

Association to add renewable energy pro-

grams to the utility’s tariff. One initiative

would involve the establishment of a

“Green Energy Program,” in which the

utility’s members would be invited to pay

a premium to purchase renewable energy

credits and fund renewable energy proj-

ects. The other initiative would invite

members to subscribe to a portion of a

utility scale community solar energy

facility that Chugach Electric would build

and operate: A subscription would entitle

a member to obtain a portion of the solar

power, as an alternative to the installation

of home-based solar panels.

In both cases, the commission said that

the proposals were insufficiently well

defined to be approved and that some out-

comes from the proposals were uncertain.

However, the commission also said that

Chugach Electric could, if it wished,

implement the Green Energy Program

outside the utility’s tariff, provided that

members were informed that the program

was not regulated and provided that the

program maintained its own accounts,

separate from the tariff accounts.

Green Energy ProgramUnder the Green Energy Program util-

ity members could choose to “green” a

percentage of their electricity usage by

paying a premium on monthly energy

bills. A proportion of the premium would

be used to purchase renewable energy

credits, while the remainder would fund

grants for renewable energy projects.

Chugach Electric would administer the

grant program, with projects eligible for

grant funding needing to connect to the

utility’s electrical system.

The commission said that it is not clear

why consumers should purchase renew-

able energy credits through the proposed

program, rather than simply purchasing

the credits themselves. The commission

also expressed concern about the appar-

ent lack of criteria for awarding grants,

and the lack of a monitoring or auditing

process for grant usage. Moreover, the

proposed program does not constitute a

utility service, the commission said.

Community solarThe commission said that the proposal

for a community solar project lacks spe-

cific details that would be necessary to

evaluate its viability. For example, at this

stage Chugach Electric has not identified

a site for the project, has not adequately

explained the mechanics of how sub-

scribers could enter and exit the program,

and has not explained how rates for

involvement in the project would be

determined if there is less than full sub-

scription to the solar farm’s capacity. And

the commission said that it has concerns

about potential rate discrimination result-

ing from a “first come, first served”

approach to signing up subscribers. A

more detailed and reasonable tariff filing

is needed for the project, the commission

said.

The commission also suggested that

Chugach Electric might consider partner-

ing with a third party for the community

solar project. A third party could poten-

tially use federal tax credits that are

unavailable to Chugach Electric and

could bear project risks, including the risk

of insufficient subscription to the service.

“It is not our intent to discourage elec-

tric utilities from designing and imple-

menting new and innovative service

offerings,” the commission wrote. l

The commission also suggestedthat Chugach Electric might

consider partnering with a thirdparty for the community solar

project.

PETROLEUM NEWS • WEEK OF APRIL 7, 2019 9

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

BP plans more Prudhoe drilling in IPALatest plan for initial participating areas of field covers July 2019-June 2020, discusses increased well work, coil tubing drilling

By KRISTEN NELSONPetroleum News

Prudhoe Bay operator BP Exploration Alaska has sub-

mitted an annual progress report for the initial partici-

pating areas of the field covering the 2018 calendar year and

its plan of development for work from July 1, 2019, through

June 30, 2020.

The company said the initial participating area of the

field, the IPA, is entering its 42nd year online and is 31 years

beyond its production plateau. For the Prudhoe Bay owners

the “key priority is on efficient production of the existing

wells and facilities,” BP said. There are more than 1,400

wells at the field, and it is well developed, but BP said there

is still an important role for development drilling which

“will continue at a pace consistent with the business environ-

ment and the ability to identify viable targets informed by

ongoing surveillance, supplemented by new seismic data

being acquired in the first half of 2019.”

BP described that new seismic as “high density broad-

band seismic” which will cover the majority of the Greater

Prudhoe Bay area and will be combined with the North

Prudhoe seismic acquired in 2015 to “provide a single con-

tinuous seismic image” across the unit, allowing for more

efficient drilling. The company said this technology

“enables denser and larger datasets to be acquired when

compared to legacy methods.”

Production Crude oil and condensate production is forecast to aver-

age 150,000 to 187,000 bpd from the IPA in 2019, down

from 186,800 bpd in 2017, with natural gas liquids for 2019

expected to be between 30,000 and 46,000 bpd. (These vol-

umes are not the same as reported Prudhoe production as

they do not include the Prudhoe satellites and a portion of

production from Point McIntyre.)

In 2018, average production rates for crude oil and con-

densate within the IPA were 174,200 barrels per day and that

rate, combined with satellite production and a portion of the

Point McIntyre field addressed in separate annual reports,

“fully utilized available PBU processing capacity within

reservoir management constraints,” the company said.

Gas production in the IPA was 2,473 billion cubic feet,

production “which continues to be governed by facility han-

dling constraints.” Re-injection was 89.3 percent of pro-

duced gas, 2,298 bcf. Natural gas liquids produced from gas

totaled some 14.8 million barrels delivered to the trans-

Alaska oil pipeline and 1 million barrels taken to the

Kuparuk River unit.

The IPA also produced 893,000 bpd of water, for a field-

wide average water cut of 84 percent, the company said.

An average of 808,000 bpd of produced water was inject-

ed at the field, with 77,000 bpd of produced water exported

for injection at satellite fields.

BP said waterflood and water alternating gas operations

continued throughout the reporting period, including the gas

cap water injection project.

Miscible gas injection also continued, with available MI

(miscible injectant) allocated based on MI efficiency, the

barrels of oil recovered per unit of MI.

2019 well activityBP said 2019 production “will largely be driven through

continuing improvements in operating efficiency, optimiz-

ing base production and wellwork.”

Some 400 rate adding jobs and some 550 non-rate adding

jobs are planned, with IPA rotary penetrations expected to be

about the same as in 2018, between five and seven.

Coil penetrations, however, will be increased from 10 in

2018 to 15-23 in 2019, with rig workovers expected to

increase from two in 2018 to from two to eight in 2019.

BP said wellwork activity “remained at a high level in

2018 with 360 rate adding jobs done and about 900 total jobs

performed.”

In 2018 a coil and rotary rig operated for a total of one

year, drilling 15 wells. There was a pause in drilling midyear

allowing BP to pursue cost and efficiency gains and evaluate

future targets for drilling. “The coil and rotary rigs were

brought back in service in December,” BP said, with future

drilling opportunities to “be identified by ongoing surveil-

lance and utilizing the new seismic being acquired and

processed in 2019-2020.”

Flow Station 2 was a focus, with eight wells drilled.

TechnologyOne project for 2019 is controls obsolescence manage-

ment, with the objective of addressing aging control system

“by installing vendor supported systems,” improving lifecy-

cle cost and minimizing the impact on production during

implementation.

BP said FS3 EMC was replaced by Control Logix in

2018 and Emerson Technologies was identified as a strategic

supplier.

“The 2019 plan includes developing technology solu-

tions and an implementation plan for remaining facilities.”

Pilot testing will continue in 2019 on the Operator

Workbench, a mobile device for field workers allowing

them to collect and input data without returning to a comput-

er station.

BP said it is also expanding use of unmanned aerial vehi-

cles for monitoring.

Major gas salesBP said that as Prudhoe Bay unit operator it has executed

a confidentiality agreement with the Alaska Gasline

Development Corp. to allow disclosure of information for

the Alaska LNG project. “To date, the PBU operator has not

received formal requests for information from AGDC,

see MORE IPA DRILLING page 11

industry to develop a framework for a sci-

ence-based, life-cycle impact assessment

review every five years, taking into account

marine and climate change impacts.

For environmental and many First

Nations organizations it was the break-

through they had long sought and left a

widespread impression that Arctic explo-

ration might have been shelved for good —

a view that was reinforced as companies

such as Imperial Oil (and its parent

ExxonMobil) and Chevron shuttered their

northern operations and suspended regulato-

ry work and planned submissions.

Imperial insisted in a letter to the

National Energy Board that it remained

“committed to the Arctic as an important

future source of energy.”

Chevron put its Beaufort plans on hold

indefinitely, citing “economic uncertainty.”

Call for assessmentBut it now appears that the freeze on

activities has far from halted work on devel-

oping new Arctic technologies or low-key

lobbying of the Canadian government to

support an independent geological, technol-

ogy, commercial and economic assessment

of oil and gas potential in the region over the

next 30 years.

The first test of how receptive the federal

government might be will occur when the

ban on issuing new exploration licenses

ends its first five-year phase in 2021.

If the Trudeau administration is toppled

in an election this October it could mean a

transfer of power to a Conservative govern-

ment led by Andrew Scheer, who is likely to

be more receptive to overtures from the

petroleum industry to revive Arctic explo-

ration.

Paul Barnes, Atlantic Canada and Arctic

director of the Canadian Association of

Petroleum Producers, has suggested to

Canada’s annual Arctic oil and gas sympo-

sium and reporters over the past two years

that the moratorium has seen Canada “fall

behind” the United States and other nations

in advancing plans to develop its vast Arctic

natural resources.

He said earlier in March that recent indi-

cations President Donald Trump might

agree to reopen the Alaska Arctic illustrates

Canada’s “lost opportunities,” while coun-

tries such as Norway and Russia are moving

ahead in their competition for investment

dollars to embark on Arctic drilling or under-

take related research.

However, he suggested that successful

exploration in the U.S. sector of the Beaufort

Sea could “increase attention” from

prospective investors in Arctic development.

ConsultationEven Canada’s Northern Affairs Minister

Dominic LeBlanc has not ruled out the

prospect of resource development, describ-

ing the moratorium as a way to advance sci-

entific and technological methods of ensur-

ing any exploration is environmentally sen-

sitive.

LeBlanc told The Canadian Press that the

2016-21 period is being used to consult with

indigenous people, governments and indus-

try to prepare a science-based report to

inform the federal review of the moratorium

in 2021.

“Done properly, oil and gas development

can bring growth and prosperity to a region

that in some cases may have been over-

looked for a long time,” said LeBlanc.

“However, the development must be

done properly with the full support of scien-

tific data and research.”

Barnes, in his presentations, has noted

that more than 300 wells have been drilled in

Canada’s Arctic spread over close to 70

years, resulting in more than 100 discoveries

and many thousands of miles of 2-D and 3-

D seismic surveys.

“The region remains vastly unexplored,

but has high potential for future discover-

ies,” he said.

Improvements in technologyBarnes has argued that oil and gas activi-

ty can safely occur in the Arctic without

harming the environment, with offshore

technology moving ahead in areas such as

marine seismic noise reduction, design and

construction of new Arctic class drilling

units, ice management, safe drilling and pro-

duction operations, well-control prevention

and response, and oil spill prevention and

response.

“There are significant policy and regula-

tory challenges that must be overcome to

capitalize on (the region’s) potential,” he

said.

He conceded that although Canada’s oil

and gas regulatory regime is “robust,” it also

requires modernizing.

Barnes said the upcoming five-year

review would be assisted if industry and

governments can provide a “realistic and

10 PETROLEUM NEWS • WEEK OF APRIL 7, 2019

FINANCE & ECONOMYCIRI increases its ownership in CINGSA

Cook Inlet Region Inc. has increased its ownership interest in Cook Inlet Natural

Gas Storage Alaska from 4.25 percent to 8.5 percent, the Alaska Native regional cor-

poration announced on April 1. The majority owner of the gas storage facility is

Semco Energy, owner of Enstar Natural Gas Co. and wholly owned subsidiary of

AltaGas Ltd.

CINGSA, located to the south of the city of Kenai on the Kenai Peninsula, provides

gas storage services for Southcentral Alaska electric and gas utilities, enabling the

warehousing of gas when Cook Inlet gas production exceeds demand and making that

stored gas available when gas demand peaks. The facility began operation in 2012.

“It’s been a good investment for us and for the region,” said Suzanne Settle, vice

president, CIRI energy and infrastructure. “CIRI purchased a 4.25 percent interest

before the facility was even constructed. It’s a vital resource for the region, both for

heating and electricity. When the opportunity arose to double our percentage interest

in CINGSA to 8.5 percent in January, we jumped.”

—ALAN BAILEY

tribute to global warming.

A White House spokesperson said the new permit issued

by Trump “dispels any uncertainty” about the project.

“Specifically, this permit reinforces, as should have been

clear all along, that the presidential permit is indeed an exer-

cise of presidential authority that is not subject to judicial

review,” she said.

Legal war declaredWhatever the Trump administration view of the presi-

dent’s powers, the opponents of XL wasted no time declar-

ing a legal war on the action.

Stephan Volker, an attorney for environmentalists who

sued to stop the project, accused Trump of launching a

“direct assault on our system of governance,” vowing to

seek a court order blocking TransCanada from resuming

construction.

He said Trump has attempted to “overturn our system of

checks and balances” in making an attack on “our

Constitution ... it must be defeated.”

Anthony Swift, director of Keystone XL for the national

Resources Defense Council, said the pipeline was a “bad

idea from Day 1” because of the threat it posed to land,

drinking water and communities from Montana and

Nebraska to the Gulf Coast.

Not tied to reviewUnlike an earlier State Department permit, which was

issued after an extensive environmental analysis required

under the National Environmental Policy Act, the new pres-

idential permit is not directly tied to any such review.

The NEPA statute that generally compels environmental

study of energy projects does not apply to the president.

That raises questions about a 2014 ruling by U.S.

District Judge Brian Morris in Montana that the govern-

ment must consider oil prices, greenhouse-gas emissions

and formulate a new spill-response strategy before allowing

the pipeline to move forward.

Analysts with ClearView Energy Partners, an independ-

ent consulting firm, said Trump’s decision to override the

previous presidential permit “appears to render ...moot” an

appeal of Morris’s ruling. That in turn could end delays in a

further State Department environmental review and void an

injunction blocking pre-construction, possibly allowing

TransCanada to resume that work in August, they said.

TransCanada Chief Executive Officer Russ Girling

praised Trump for making it clear “he wants to create jobs

and advance U.S. energy security and Keystone XL does

both of those things.”

U.S. refiners have been seeking new supplies of heavy

crude after sanctions against Venezuela have reduced

imports from that country to zero, while Canadian produc-

ers have been desperate to get new export pipelines built.

Line 3The US$9 billion Line 3 plan proposal covering 1,000

miles of aging pipe from Alberta to Wisconsin and doubling

current capacity to 760,000 bpd gained a sizeable boost

when the Minnesota PUC unanimously rejected the last

pending petitions to block construction, including one from

the Minnesota Commerce Department to join Indian tribes

and environmental groups in challenging project approvals.

Minnesota Gov. Tim Walz, who has opposed Line 3, said

his administration will study the PUC ruling before decid-

ing on its next steps.

Enbridge still needs state and federal permits, which it

hopes to obtain later this year.

It had earlier forecast that the regulatory delays could

postpone completion of the pipeline replacement by almost

a year until the second half of 2020. l

continued from page 1

PIPELINE HOPE

continued from page 1

ARCTIC STIRS

see ARCTIC STIRS page 11

Thibert. “We know we will save electric

ratepayers money over the long-term with

this acquisition. We look forward to out-

lining our case to the RCA and moving

forward with this effort that will have a

positive impact in Anchorage for decades

to come.”

“The amount of work and effort from

Chugach, ML&P and the city getting to

this point has been outstanding,” said

Bettina Chastain, chair of the Chugach

Electric board. “The timing was right and

everybody came together, putting their

best foot forward to do something that

will be good for the community as a

whole.”

$200 million in savingsChugach Electric told the RCA that it

anticipates a net present value of more

than $200 million in savings over the next

40 years as a consequence of the merger

of the two utilities. Chugach Electric

anticipates the approval process taking

about six months to complete. During that

time teams from Chugach Electric and

ML&P will formulate a plan for combin-

ing the utilities, to minimize disruption to

customers, employees and the communi-

ty. Assuming that closure of the deal

would take about 120 days after RCA

approval, the two utilities would finally

merge around February 2020.

RCA approval is needed for the con-

tractual and financial arrangements for

the deal, and for the future recovery from

electricity rates of the costs of the merger.

Chugach Electric’s certificate of public

convenience and necessity will also need

to be modified to reflect, among other

things, the change to the utility’s service

territory.

Two key commitments in the deal are

that no employees will be laid off and that

customers’ electricity rates will not

change when the merger takes place.

Over time, employment levels in the con-

solidated utility will drop through natural

attrition, thus enabling cost savings.

Electricity rates will ultimately change, as

the economics of the electricity supplies

evolve. However, Chugach Electric antic-

ipates those rates being lower than they

would have been, had the two utilities

remained separate.

Three componentsThere are three components to the

financial arrangements for the deal: an

upfront payment of about $768 million by

Chugach Electric; annual payments by

Chugach Electric to the Municipality of

Anchorage for power from the municipal-

ity-owned Eklutna hydroelectric power

plant; and annual payments in lieu of tax

to the municipality. The resulting net

present value of what Chugach Electric

will pay to the municipality for the

ML&P acquisition will be around $1 bil-

lion spread over a 50-year period.

Chugach Electric told the RCA that the

upfront payment includes the cost of pay-

ing off ML&P’s bonds and amounts to

$48 million in excess of the net book

value of ML&P’s assets.

Eklutna power purchaseThe agreement for the purchase of

Eklutna power, which would continue for

35 years, was formulated as an alternative

to an original concept of Chugach

Electric simply making annual payments

to the municipality, in addition to the

upfront payment — that original concept

suffered from, in effect, being unsecured

financing for the purchase. Instead, the

municipality will retain ownership of the

Eklutna power station while Chugach

Electric will operate the facility for the

municipality. Pricing for the Eklutna

power that Chugach Electric will pur-

chase will be based on the avoided cost of

power generation that Chugach Electric

would otherwise have needed. Payment

for the Eklutna power will have an equiv-

alent end result to making those originally

conceived annual payments.

In recognition of the fact that some

Matanuska Electric Association members

live within the northern part of Anchorage

but would not directly benefit from the

sale of ML&P, MEA has an option to pur-

chase an increased share of the Eklutna

plant. That would enable the MEA cus-

tomers to benefit from access to more rel-

ative cheap hydropower but would reduce

the municipality’s income from the

hydropower plant.

PILT paymentsThe annual payments in lieu of tax will

exactly replace the municipality utility

service assessment, or MUSA, that the

municipality currently receives from

ML&P via the rates that ML&P charges

its customers. In effect, the MUSA pay-

ments represent income to the municipal-

ity from its ownership of ML&P.

Chugach Electric emphasized to the RCA

that the proposed PILT payments would

not represent an incremental cost to cus-

tomers, because the PILT payments will

be exactly equivalent to those current

MUSA payments.

Moreover, to maintain that equiva-

lence and ensure that Chugach Electric

existing customers are not penalized,

until 2033 the PILT payments will only be

recovered from customers inside ML&P’s

current service area.

And the PILT payments, by maintain-

ing an existing revenue stream for the

municipality, will enable the municipality

to sell ML&P without having to increase

property taxes in Anchorage as a conse-

quence.

Beluga gasAnother complication results from the

fact that both Chugach Electric and

ML&P own portions of the Beluga River

gas field on the west side of Cook Inlet

and obtain some of their power station

fuel gas from that field. The prices that

the two utilities pay, in effect for their

own gas, differ with the ML&P gas being

cheaper. As with the PILT payments,

accounting for the cost of the gas would

remain separate for the ML&P service

area until 2033, thus enabling the relative-

ly cheap gas to offset the impact of the

PILT within the service area. l

PETROLEUM NEWS • WEEK OF APRIL 7, 2019 11

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FERC, or any other agency, any other unit

operator, or any third party regarding the

AGDC-led AKLNG project,” but said it

anticipates responding to requests as they

arise.

“In 2018, the unit operator, working

with AGDC, presented PBU geoscience

and engineering data including prospec-

tive gas sales forecasts to a prospective

buyer,” BP said.

The company listed activities which

Prudhoe Bay unit owners anticipate

would be needed to ensure alignment

with an AGDC-led project, should AGDC

decide to proceed with AKLNG:

•The tie-ins at the PBU Central Gas

Facility to connect with AKLNG Gas

Treatment Plant feed gas line, value man-

ifold module and custody transfer meter-

ing module at the CGF pad would need to

be identified and designed and installation

coordinated with AGDC.

•In the event of short-term outages of

the trans-Alaska pipeline, facilities would

need to be identified, designed and coor-

dinated to mitigate the impact on gas

delivery.

•CGF low temperature separators

would need to be identified, designed and

modified to meet GTP inlet gas specifica-

tions.

•For byproduct injection, BP said the

PBU owners will need to identify, design

and coordinate installation of high-pres-

sure pipelines to various pads and will

also need to drill wells for byproduct

injection.

•GTP byproduct flare will be needed

for unplanned emergency depressuriza-

tion to mitigate CO2 related hazards.

•For shared infrastructure it will be

necessary to identify potential sharing

arrangements for fuel gas, power and

propane for GTP construction.

•Operating and maintenance plans will

need to be developed for wells and facili-

ties to produce and deliver gas at requisite

availability on annual average basis.

•Maintenance programs will need to

be developed for existing facilities to

maintain facilities integrity and to sustain

reliable gas supply. l

continued from page 9

MORE IPA DRILLING

continued from page 1

ML&P DEAL

mark Brent price.

Analysts credited the price rally to

fresh evidence of the Organization of

Petroleum Exporting Countries supply

cuts and lessening of worries about global

economic growth largely based on

Chinese manufacturing data.

The cuts came from Saudi Arabia,

with OPEC’s output slipping in March for

the fourth straight month.

“It’s OPEC, for once sticking to their

supply constraints,” Scott Bauer, chief

executive officer of Prosper Trading

Academy in Chicago, was quoted as say-

ing in a Bloomberg report. “In the past,

they haven’t really heeded their own

guidance. But this time they are, and it

looks like it’s going to stay that way for

the foreseeable future.”

A survey by Reuters showed OPEC

members pumping 30.4 million barrels a

day in March, down 280,000 bpd from

February — the lowest OPEC total since

2015.

According to the same Bloomberg

report, “China’s manufacturing purchas-

ing managers’ index recorded its biggest

increase since 2012” in March, “exceed-

ing all estimates by economists. The news

lifted equity markets worldwide, with

Hong Kong’s Hang Seng index entering

into a bull market.”

—KAY CASHMAN

continued from page 1

OIL PRICES

credible economic appraisal on the future

and times of Arctic oil and gas potential,”

calling for an independent study covering

geological, commercial and economic

issues.

He suggested research and development

priorities could include:

•Commercialization of remote sensing

technologies and advancing northern capac-

ity to deliver remote sensing services.

•Advancing resource development and

safety and security applications.

•Iceberg detection, threat analysis and

drift forecasting and towing automation.

•The detection and mitigation of oil spills

in sea ice.

•Advancing Arctic knowledge to

improve economic opportunities, using the

resources of Canada’s High Arctic Research

Station.

—GARY PARK

continued from page 10

ARCTIC STIRS

12 PETROLEUM NEWS • WEEK OF APRIL 7, 2019

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entire Beaufort Sea planning area, with

possibilities for taking account of areas

of particular environmental sensitivity or

of importance for subsistence whaling.

Clearly, the reversal of Trump’s order

will severely restrict the area that can

now be offered for leasing — Obama did

not withdraw a 2.8 million acre strip of

the Beaufort Sea with relatively high oil

and gas potential, immediately north of

the coastline, between Smith Bay and

the western side of Camden Bay.

The District Court decision may be

appealed to the U.S. Court of Appeals

for the 9th Circuit, and ultimately to the

U.S. Supreme Court.

OCSLA section 12(a)Obama carried out his withdrawal

order under the terms of section 12(a) of

the Outer Continental Shelf Lands Act,

the act that provides the statutory frame-

work for resource development on the

outer continental shelf. Section 12(a) of

the act states that “the president of the

United States may, from time to time,

withdraw from disposition any of the

unleased lands of the outer continental

shelf.” Thus, while the act clearly gives

the president legal authority to conduct

land withdrawals, the wording of the act

makes no explicit statement regarding

the circumstances, if any, under which a

land withdrawal may be reversed.

Judge Gleason, in her court order,

commented that the phrase “from time to

time” introduces an element of ambigui-

ty into the statute, in that it could be

interpreted as meaning that the president

could conduct withdrawals at various

times, or as meaning that each president

could revoke or modify any prior with-

drawal. However, the structure of

OCSLA supports a view that section

12(a) of the act does not give the presi-

dent the authority to revoke a previous

land withdrawal, Gleason wrote.

Intent of CongressGleason also supported a view that,

had Congress intended that a president

should have the authority to revoke a

withdrawal, Congress would have

explicitly stated this in the act.

Moreover, the fact that Congress gave

the president authority to withdraw lands

from leasing without explicitly giving

authority for revoking a withdrawal is

consistent with the purpose of OCSLA,

Gleason wrote. She also commented that

there is insufficient evidence, based on

Congress’s inaction over the wording of

section 12(a) of the act, to infer any con-

clusion that would override the court’s

interpretation of that section.

Thus, the court has ruled that the

presidential order revoking Obama’s

2016 land withdrawal is unlawful,

Gleason wrote.

Controversial decision“I am disappointed by this ruling and

its implications for the state and national

economy,” said Alaska Gov. Mike

Dunleavy in response to the court ruling.

“Alaska’s potential offshore oil and gas

deposits, if given the opportunity to be

safely and responsibly developed, can

create jobs, revenue and economic

opportunity for decades. One president

should not have the power to lock up

Alaska’s resources in perpetuity.

America needs Alaska’s natural

resources.”

“I strongly disagree with this ruling,

which asserts that past presidents can

bind their successors and only Congress

can overturn those decisions,” said U.S.

Sen. Lisa Murkowski, R-Alaska. “That

is not the correct interpretation of the

Outer Continental Shelf Lands Act and

could have catastrophic impacts for off-

shore development, which creates jobs,

generates revenues, and strengthens our

national security. I expect this decision

to be appealed and ultimately overturned

— if not by the 9th Circuit, then by the

Supreme Court.”

“This victory shows that no one, not

even Trump, is above the law,” wrote

Gene Karpinski, president of the League

of Conservation Voters, one of the plain-

tiffs in the case. “Offshore drilling and

the associated threat of devastating oil

spills puts coastal economies and ways

of life at risk while worsening the conse-

quences of climate change. President

Trump wanted to erase all the environ-

mental progress we’ve made, but we

fought back and we won.” l

that the KIC well did not make a significant

oil find. Apparently the lawsuit revolved

around whether the shareholders of

Standard Oil of Ohio, or Sohio, had been

adequately compensated when Sohio

became part of BP. A merger between the

companies had been negotiated in 1968 —

subsequently for a number of years BP’s

activities in Alaska had been conducted as

Sohio. At issue in the Cleveland court case

had been whether, in the terms of the Sohio

acquisition, BP had sufficiently valued its

potential oil reserves in ANWR. Critical to

that ANWR valuation were the results from

the KIC well.

A worthless well?Although some documents from the

court case are missing and critical tran-

scripts from the court hearings were not

made public, the fact that the eventual set-

tlement with Sohio shareholders only

involved a small increase in BP’s offer

price suggests that little value was attached

to the KIC well results. Moreover, lawyers

representing a California public employee

retirement system, a major Sohio share-

holder, were allowed to see the drilling

results and concluded that the results pro-

vided no legal basis for questioning the fair-

ness of the price, the New York Times

reported.

A lawyer who was involved in the court

case told the New York Times that his rec-

ollection is that the KIC well was worth-

less. A person, who at the time of the case

was a BP executive who prepared a deposi-

tion for the court, told the Times that his

recollection is that there was no particularly

encouraging find in the well. In addition,

during the court case a Goldman Sachs

banker testified that BP had led him to

believe that the well results were not

encouraging, the New York Times reported.

So what might this mean in terms of the

oil potential of the ANWR coastal plain, the

so-called 1002 area?

USGS assessmentIn 1998 the U.S. Geological Survey esti-

mated that there may be somewhere in the

range of 5.7 billion to 16 billion barrels of

undiscovered, technically recoverable oil in

the 1002 area. And, since the USGS has

never had access to the results from the

KIC well, those results have no bearing on

the findings of the USGS assessment.

Essentially, the USGS scientists identify

distinct potential oil plays, known as

assessment units, within a region such as

the 1002 area. The scientists use seismic

data to find possible oil traps within each

play, subsequently using statistical tech-

niques add up and evaluate the uncertainty

of possible undiscovered oil volumes in the

plays.

The KIC well was drilled in the more

eastern part of the 1002 area, in a region

sometimes referred to as the deformed area,

because of the known presence of signifi-

cant folds and geologic faults in the strata.

Near the coast there are major structures

with apparent similarities to the structures

in the central North Slope where producing

North Slope oil fields are located — this

structural similarity likely influenced the

choice of location for the KIC well.

Different geologyHowever, the geology in this part of

1002 area is distinctly different from that of

the central North Slope. In particular, many

of the older rocks that sourced and reser-

voired oil in the central North Slope were

eroded out at some time in the geologic

past. The older rocks are preserved in some

sunken faulted blocks, offshore under the

Beaufort Sea, but it is not clear whether this

phenomenon extends under the onshore

region.

USGS geologist Dave Houseknecht, an

expert on North Slope petroleum geology,

has told Petroleum News that, although

there is uncertainty regarding the presence

of two major source rocks, the Shublik and

the Kingak, in the eastern 1002 area, there

is good evidence for the presence of at least

two good source rock intervals in the

younger Brookian sequence, including the

Hue shale/GRZ. And potential Brookian

reservoir rocks are definitely present.

In the more westerly part of the 1002

area, the subsurface strata are relatively

undeformed. The exploration interest here

would primarily be in stratigraphic oil

traps, traps formed from the manner in

which the sediments that formed the rocks

were deposited. With known significant

thicknesses of Brookian strata in the region,

the exploration plays would be analogous

to those in which major oil finds have been

made in the Nanushuk and Torok forma-

tions to the west of the central North Slope.

—ALAN BAILEY

continued from page 1

ARCTIC OCS

continued from page 1

KIC WELL