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page10

Tangen: Court says MLUP can be functionally Irrevocable www.MiningNewsNorth.com The weekly mining newspaper for Alaska and Canada's North Week of June 21, 2015

NEWS NUGGETSCompiled by Shane Lasley

l R A R E E A R T H E L E M E N T S

Unga delivers high-grade gold-silverRedstar Gold Corp. June 11 reported multi-ounce gold

intercepts from the first two holes of a recently completed

eight-hole drill program on the Shumagin prospect at its

Unga gold project on the Alaska Peninsula. Hole 15SH011

cut 1.9 meters grading 5.89 ounces per ton gold and 2.4 oz/t

silver over 1.9 meters. Hole 15SH012 cut three intercepts:

1.03 oz/t gold and 6.1 oz/t silver over 2.0 meters; 0.49 oz/t

gold and 5.3 oz/t silver over 3.0 meters; and 3.88 oz/t gold

and 12.3 oz/t silver over 0.7 meters. “These are the drill

results from a new management team, and these results con-

firm our optimism for the Unga Gold Project, and the

Shumagin area specifically. We intersected mineralization

where we expected, with high-grade gold and silver grades,”

said Redstar Chairman Jacques Vaillancourt. The phase-1

program at Unga was designed to target various structural

elevations of the Shumagin vein system while systematically

testing for continuity of mineralization and obtaining geo-

logical constraint within areas of existing known high-grade

mineralization through infill drill holes, including the holes

reported above; and exploratory step-out drilling of the vein

system at depth and along strike to the northeast by about

100 meters through four step-out drill holes. Results from

the remaining six holes are pending. Redstar said a phase-2

drill program planned for later 2015 will maintain a focus on

the Shumagin prospect concurrent with exploration of other

known high-grade gold targets located within the Unga gold

project.

Graphite Creek claims conflict settledGraphite One Resources Inc. June 11 reported that its

wholly owned subsidiary, Graphite One (Alaska) Inc. has

come to an agreement with Ronald Sheardown for 28 Alaska

state mining claims covering the same lands purchased by

Graphite One in January 2012. This provides the company

ownership of both the jun-

ior and senior state mining

claims that overlap and

surround the 24 unpatented

federal claims that it leased

from Kougarok LLC. In

exchange for the claims,

Graphite One has agreed to

pay US$50,000 and issue 3

million common shares to

Sheardown. Sheardown

also will receive a royalty

interest equal to 1 percent of the net smelter returns received

on G1 Alaska claims, subject to Graphite One’s option to

purchase the royalty for US$500,000 at any time within 36

months following the start of mine production. Graphite One

Bottom of Formalso retained Sheardown to sit on its adviso-

ry board for three years. As part of this position, Sheardown

has been granted stock options to purchase 1 million

Graphite One common shares at C13 cents per share.

Graphite One’s Graphite Creek property now includes the 28

state mining claims acquired by G1 Alaska in 2012 plus the

claims acquired from Sheardown, 77 state claims staked by

G1 Alaska in 2012 and 24 leased federal claims. “With this

agreement, Graphite One (Alaska) now fully controls, free

of any conflicting locations, the right to possess and extract

100 percent of its identified resource,” said Graphite One

CEO Anthony Huston. “The company will also benefit from

being able to draw on Ron Sheardown’s extensive experi-

ence in major development projects, and he will be a great

asset to our board and management. Sheardown has been

see NEWS NUGGETS page 11

Ahead of the REE crowdUcore’s separation process draws investor; explorer eyes Bokan feasibility

By SHANE LASLEYMining News

Ucore Rare Metals Inc.’s exploration endeav-

ors are proving successful – not only in

expanding the heavy rare earth elements-enriched

deposit at the Bokan Mountain Project in

Southeast Alaska, but in discovering new tech-

nologies that advance rare earth refinement into

the 21st Century.

Hoping to cash in on this success, a “high net-

worth” American investor recently tendered a

US$1 million down payment toward royalties

offered by Ucore.

These royalties will not

come from the future sale of

rare earths mined at Bokan

Mountain. Instead, they will

derive from the sale of prod-

ucts and services related to

SuperLig

Molecular

Recognition Technology, a

proprietary rare earths and

specialty metals separation

method that

Ucore is

involved with developing.

All told, the un-named investor has agreed to

pay US$4 million in exchange for royalties associ-

ated with the cutting-edge REE separation technol-

ogy.

“The investment is favorable for Ucore since

there is no debt burden, and is prospectively non-

dilutive, given that shares will not be issued by

Ucore upon closing,” said Ucore President and

CEO Jim McKenzie. “What’s more, the transac-

tion is a vote of confidence from a major investor

in the remarkable growth potential of MRT, as well

as an endorsement and financing milestone for

Ucore, as it transitions towards near-term revenue

status and vertical integration.”

Separate technologyIBC Advanced Technologies, a Utah-based

company that develops and manufactures molecu-

lar recognition technology for a broad range of

applications, has successfully applied the tech-

nique to separating notoriously tightly interlocked

rare earth elements.

The MRT process is designed to bind selective-

ly with ions based on multiple parameters such as

size, chemistry, and geometry.

Using a pregnant leach solution prepared from

material taken from Dotson Ridge deposit at

Bokan Mountain, IBC Advanced Technologies

developed a three-step process for creating nearly

pure rare earths.

On June 16, Ucore announced that Dr. Reed

Izatt, a chemist and one of the founding principles

of IBC Advanced Technologies, and Steven Izatt,

president and CEO of IBC, would be joining

Ucore’s advisory board.

“With Ucore’s expanding focus on metals sepa-

ration technologies, the insights provided by Dr.

Reed Izatt and Mr. Steven Izatt, combined with the

benefit of IBC’s experience as the global leader in

MRT applications to the mining industry, will be

invaluable,” explained McKenzie.

In early March, Ucore reported that IBC’s MRT

process had separated all the individual rare earth

elements found at Bokan Mountain into salts of

greater than 99 percent purity, except for samarium

and gadolinium, which remained bound together.

Samarium and gadolinium have now been sep-

arated into individual salts, each with 99.2 percent

purity.

Not only did the process create pure salts across

the entire suite of rare earths, it did so while recov-

ering more than 99 percent of the REEs available

in the pregnant leach solution.

“We look forward to completing pilot-scale

testing of this promising nano-technology,” said

McKenzie.

Upon delivery of a fully functional pilot plant,

Ucore has agreed to pay IBC US$2.9 million for

rights to the potentially sector-changing technolo-

gy.

Under an agreement announced in March,

Ucore will hold a 60 percent interest in a joint ven-

ture with IBC to market and sell SuperLig

Molecular Recognition Technology for rare earth

separation and recycling applications, as well as

tailings processing applications.

“Perhaps most importantly, our licensing

arrangement includes the application of SuperLig

technology to the world recycling and tailings pro-

cessing sector – both for the recovery of rare earths

and all other metals,” McKenzie said at the time.

The US$4 million from the yet-to-be-named

investor will help pay for the rights.

In exchange, the investor will be granted royal-

ties equal to five percent of gross sales from the

first MRT installation or installations, payable

until the investment is recouped; and a net smelter

royalty equal to 2 percent of the net sales from

Ucore’s first C$50-million-per-year molecular

recognition technology client.

The investor has the option to increase the roy-

alty by up to 0.5 percent by putting up another

US$1 million by Aug. 13. An option to trade in the

royalties for Ucore shares is also on the table.

Upgrading BokanIn addition to finding new and improved ways

to separate rare earths, Ucore’s exploration has sig-

nificantly upgraded and expanded the REE

resources at the Dotson Ridge deposit of its Bokan

Mountain project.

This expansion is the result of a 4,000-meter

drill program completed last year.

The smaller of two rigs drilling at Bokan during

2014 focused on upgrading inferred resources to

the indicated category by infill drilling of the rare

earths deposit.

Of the 12 infill holes drilled, 10 cut significant

mineralization. One hole, LM 14-142, cut multiple

intercepts exceeding 1 percent TREO. Highlights

see UCORE PROGRESS page 11

“We look forward to completing pilot-scale testing of this promising nano-

technology.” —Jim McKenzie, presidentand CEO, Ucore Rare Metals Inc.

JIM MCKENZIE

This provides the companyownership of both thejunior and senior state

mining claims that overlapand surround the 24

unpatented federal claimsthat it leased from

Kougarok LLC.

This week’s Mining News

Rare earth element miner Ucore Rare Metals Inc. draws an investorfor its separation process. Read more in Mining News, page 9.

page3

Q&A: Same guy, different job,Persily from federal office to KPB

Linc outlines UmiatAustralian independent describes expanded development program for oil field

By ERIC LIDJIFor Petroleum News

A fter spending more than a year evaluating

drilling results, Linc Energy Ltd. has consider-

ably expanded its proposal for developing the

Umiat oil field on the North Slope.

The Australian independent recently outlined a

program calling for approximately 13 drilling pads

to accommodate 150 wells with drilling to begin as

early as 2021. The program is twice as large as and

would take several years longer than a previous ver-

sion.

The company has drilled two exploration wells

in recent years at the known oil field in the foothills

of the Brooks Range Mountains and the National

Petroleum Reserve-Alaska.

Umiat No. 18 in early 2013 took a vertical core

sample. Umiat No. 23H in early 2014 followed up

with the first horizontal well ever drilled at the

remote field. A subsequent flow test yielded a sus-

tained rate of 250 barrels per day of 38.5 degree API

gravity crude oil.

Those wells formed the foundation for reservoir

modeling efforts currently under way.

The company is envisioning a drilling program

with wells laid out of a 40-acre pattern, with wells

The season approachesShell starts moving fleet north for Chukchi drilling; permits slot into place

By ALAN BAILEYPetroleum News

E lements of Shell’s Chukchi Sea fleet are on

the move, heading north in preparation for

drilling during this season’s Arctic open water sea-

son.

The barge Arctic Challenger, holding Shell’s

Arctic oil containment system, a part of the com-

pany’s oil spill response capability, arrived in the

Aleutian Islands port of Dutch Harbor on June 14,

Shell spokeswoman Megan Baldino told

Petroleum News in a June 16 email. The semi-sub-

mersible drilling platform Transocean Polar

Pioneer is en route for Alaska, having left Seattle

on the U.S. West Coast at around 6 a.m. on June

15, Baldino said. Shell’s other drilling vessel, the

Noble Discoverer, remains at the Port of Everett to

continue its load out, she said.

Shell now has in place most of the permits that

Petronas at starting gateAsian partnership gives big lift to Canada’s energy industry with vow to proceed

By GARY PARKFor Petroleum News

A wide-ranging Asian consortium backing

British Columbia’s Pacific NorthWest LNG

consortium has become the first of 17 LNG pro-

posals in the province to make a solid commitment

to go ahead with its plans by investing C$12 bil-

lion to produce, process and ship Canadian natural

gas to the owners’ home markets.

TransCanada also reported four additional

agreements with First Nations, helping clear the

way for a C$5 billion investment linking shale gas

fields to the Pacific NorthWest liquefaction termi-

nal on Lelu Island, south of Prince Rupert.

The decision to tie the final knots on Canada’s

first LNG export venture came as the British

Columbia Legislature was winding up its spring

session, triggering a flush of excitement in a gov-

ernment that has pinned much of British

Columbia’s economic future on returns from LNG.

Deputy Premier and Natural Gas Development

Minister Rich Coleman described the announce-

ment by project operator, Malaysia’s state-owned

Petronas, as “a significant milestone for us.”

The Australian independent recentlyoutlined a program calling for

approximately 13 drilling pads toaccommodate 150 wells with drilling to

begin as early as 2021.

see UMIAT PROGRAM page 19

The company has assembled a major setof assets for responding to any oil spillemergency, including the containmentdome, a well capping stack, oil spillresponse vessels and a tanker for

collecting any spilled oil.

see DRILLING FLEET page 20

see ENERGY LIFT page 18

Coleman said that British Columbia’s vastgas resource, most of it stuck in the ground

with nowhere to go, is “basically sold.”

Caelus buying Smith Bay tractsfrom NordAq; plans winter drilling

Caelus Energy Alaska is expanding its North Slope opera-

tions to the west, acquiring 26 tracts in Smith Bay from

NordAq, and has announced plans to drill the Tulimaniq leas-

es this winter. Pat Foley, senior vice president of the compa-

ny’s Alaska operations, told a joint meeting of the House and

Senate Resources committees June 17 that he’d been locked in

a room for the past two days with representatives of NordAq,

Doyon Drilling, Cruz Construction and CIRI, finalizing the

deal, expected to close June 18 and be recorded June 19. He

said NordAq, which had planned to drill this past winter, was-

n’t able to carry out those plans.

A June 17 press release from Caelus, released after the June

17 committee hearing, said the company is acquiring a 75 per-

AIDEA buying Pentex; boardapproves $54 million acquisition

The Alaska Industrial Development and Export Authority will

buy a Fairbanks natural gas distribution utility in the hopes of

streamlining efforts to bring gas to the Interior.

The board of the public corporation approved a resolution

June 11 allowing AIDEA to invest $54 million to acquire Pentex

Alaska Natural Gas Co. LLC. The sale includes assets of the

company, including its distribution subsidiary Fairbanks Natural

Gas LLC.

Although AIDEA is touting immediate cost savings, the inten-

tion of the purchase is to quickly “transition” Fairbanks Natural

Gas to a “local control entity,” such as the municipal Interior Gas

Utility or the cooperative Golden Valley Electric Association.

The acquisition is expected to close by the end of July.

see CAELUS TRACTS page 18

see AIDEA BUY page 19

2 PETROLEUM NEWS • WEEK OF JUNE 21, 2015

Petroleum News North America’s source for oil and gas newscontents

14 Cook Inlet Energy surrenders spare leases

Company returns 14 un-unitized leases throughoutthe Cook Inlet basin; independent investors make smaller transactions

13 Tax credits based on spend, taxes on price

Legislative committees hear admin overview on oil taxcredits, enalytica analysis, small producers, explorers on value of credits

7 M&A uncertainty prevails

Hopes for a gusher of deals in Canada lack clarity; signs from Crescent Point-Legacy deal pointto interest in energy assets by SOE

FINANCE & ECONOMY

3 Same guy, different job, renewed energy

Persily switches from federal to Kenai Peninsula Boroughoffice while tapping into wells of diverse skillsfor projected AKLNG hub

4 Alberta jitters grow

New government makes good on promise to raiseincome tax, expects to start review of royalties, climate policies later this year

GOVERNMENT

8 Legislators get update on Alaska LNG

Project work on schedule for 2016 FEED decision; fiscalcertainty from state needed; continuing role of TransCanada uncertain

NATURAL GAS

5 Reflections on Railbelt grid issues

RCA commissioners comment on some of the issuesrelating to the potential for unified operation of the power transmission system

6 ML&P proposes power dispatch solution

Offers service to utilities to help make best use of available electricity generation facilities on the Railbelt transmission grid

UTILITIES

15 Walsh named state pipeline coordinator

LAND & LEASING6 No substantial new info decisions

Caelus buying Smith Bay tractsfrom NordAq; plans winter drilling

AIDEA buying Pentex; boardapproves $54 million acquisition

Linc outlines Umiat

Australian independent describes expanded development program for oil field

The season approaches

Shell starts moving fleet north for Chukchidrilling; permits slot into place

Petronas at starting gate

Asian partnership gives big lift to Canada’senergy industry with vow to proceed

ON THE COVER

page11

Parnell heads governors’ 7-membercoastal states coalition E X P L O R A T I O N & P R O D U C T I O N

N A T U R A L G A S

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

Vol. 17, No. 44 • www.PetroleumNews.comA weekly oil & gas newspaper based in Anchorage, Alaska

Week of October 28, 2012 • $2

The October issue of North of 60 Mining News is enclosed.

October Mining News inside

PHOTO BY CHRIS AREN D, COURT ES Y OF USI BELLI COA L MI NE I NC .

Thomas Tak e, ch arged w ith the large task of repairing

tires at the U sibelli Coal M ine in Healy, holds one of

some 4,500 high-paying mining jobs in Alaska. An

employment forecast published by the Alaska

Depa rtment of Labor and W or kforce Development in

October pegged the state’s mining sector job grow th

from 2010 t o 2020 at 19 percent. Page 14.

A special supplement to Petroleum NewsWEEK OFOctober 28, 2012

3 P en t a g o n ba ck s U cor e in no v a tio n

Contract ties DoD to Bokan, state-of-the-art method for extracting REEs

11 E m er a l ds g l im m e r in g o ld s e tt i n g

North C ountry Gold makes rare gem discovery in Nunavut greenstone belt

24 N e w G old t h ir s t y f or B l a ck w a te r

Miner dri lls 250,000 meters, makes vast land grab in gold-rich central BC

Budget planners cautious; landsales, well authorizations down

Bean counters and number crunchers are in full swing in

Canada assembling 2013 capital budgets against a worrying

backdrop of shaky industry forecasts, sharp declines in gov-

ernment land auctions and plunging new well permits issued

by regulators.The current betting points to troubles for the upstream,

reflected in gyrating oil and natural gas prices, and a contin-

uation of the lackluster showing in the drilling sector that has

extended over recent years.One of the early messages came from Schlumberger Chief

Executive Officer Paal Kibsgaard, who told analysts that liq-

uids activity in North America will “no longer be able to off-Hanging pipeline: September floodsleave Kenai area gas line dangling

Roads and railroad bridges weren’t the only things that

washed out in the heavy rains which hit Southcentral Alaska

in September. Marathon Oil, in the process of selling its Cook Inlet

assets to Hilcorp Alaska, is dealing with a washout along

Kalifonsky Beach Road near Kenai which left a segment of a

gas pipeline dangling. The Pipeline and Hazardous Materials Safety

Administration, PHMSA, described the situation and action it

requires in an Oct. 5 corrective action order. The affected line is a 20-inch diameter pipeline transport-

ing natural gas from the Kenai gas field to facilities south of

Kenai. PHMSA said the line was buried parallel to and with-

see BUDGET CAUTION page 18

see FLOODING AFTERMATH page 21

CD-5 is aliveConoco sanctions Alpine West; now needs partner approval; first oil by 2016

By ERIC LIDJIFor Petroleum NewsA fter years of permitting delays, ConocoPhillipsCo. is moving ahead on CD-5, the fourth satel-

lite of its Alpine field on the North Slope, the com-

pany announced Oct. 25.The ConocoPhillips board sanctioned the project

in October, Executive Vice President Exploration

and Production Matt Fox said during a third quarter

earnings call. “The project is now pending partner

approval, which is expected in November,” Fox said.

ConocoPhillips expects CD-5 production to begin

in 2016, Fox said. The company previously estimat-

ed construction would begin in 2014 with first oil in

late 2015.

After bringing the Alpine field at the Colville

River unit into production in 2000, ConocoPhillips

and its partner Anadarko brought three Alpine satel-

lites online over the following decade: Fiord in

August 2006, Nanuq in December 2006 and Qannik

in 2008. Also known as Alpine West, the CD-5 satellite

ConocoPhillips produced some 176,000barrels of oil equivalent per day in

Alaska during the third quarter, downsome 32,000 barrels of oil equivalent per

day from the same period last year.

see CD-5 page 22New field ‘challenge’ExxonMobil: Schedule is tight for achieving first production at Point Thomson

By WESLEY LOYFor Petroleum NewsM eeting the target date for starting productionfrom Alaska’s Point Thomson field will be “a

challenge,” an ExxonMobil executive said.The company has pledged to start producing natu-

ral gas condensate from the remote eastern North

Slope field by the winter of 2015-16.But it still has multiple permitting hurdles to clear

before it can begin construction of production facili-

ties and a pipeline to feed the condensate into the

existing North Slope transportation network.Company representatives appeared Oct. 23 at a

hearing of the Regulatory Commission of Alaska,

which is considering an ExxonMobil subsidiary’s

application for a certificate of public convenience and

necessity to build and operate the 22-mile pipeline.

One commissioner asked the ExxonMobil reps

whether they are on schedule with the Point Thomson

project.“We are on schedule, but it is very tight,” replied

Jeff Ray, vice president of PTE Pipeline LLC, the

company seeking the certificate for the Point

Aside from the certificate, ExxonMobilneeds a number of other major

authorizations before it can proceed withthe Point Thomson development.

see TIGHT SCHEDULE page 23Time for action is hereSouthcentral Alaska utilities are moving forward on options for gas imports

By ALAN BAILEYPetroleum NewsWith natural gas supplies from Cook Inlet set

to fall short of local gas demand by 2014 or

2015, the time has come tomove ahead with arrange-ments to supplement thoselocal supplies with importsfrom elsewhere, Southcentralpower and gas utility executives told the

Regulatory Commission of Alaska during a public

meeting on Oct. 24. Southcentral residents and

businesses depend on gas both for power genera-

tion and for the heating of buildings.“I’m personally done wringing my hands,”

Bradley Evans, CEO of Chugach Electric

Association, told the commissioners, saying he

takes responsibility for ensuring continuity of gas

supplies for his utility. Chugach Electric currently

generates about 90 percent its power using gas-

fueled power plants.

Lee Thibert, senior vice president ofChugach Electric, said that the utilities

have asked potential shippers of importedgas for expressions of interest in theimport arrangements.

see GAS IMPORTS page 24

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By STEVE QUINNFor Petroleum News

T here doesn’t seem to be much

Larry Persily hasn’t done.

Reporter. Legislative aide. Editorial

writer. Deputy Revenue Commissioner.

Federal Pipeline Coordinator.

Now Persily calls the Kenai Peninsula

Borough his new employer. Mayor Mike

Navarre needed an oil and gas specialist

to tend to details but also do some heavy

lifting on major projects. His wealth of

knowledge on resource development,

particularly the Alaska LNG project, will

be the most visible, but Persily’s new job

as a special assistant runs deeper than

that.

Persily talked about his new role after

the federal pipeline coordinator’s office

closed over the winter, and his views on

the prospective LNG project.

Petroleum News: So talk about yournew job a little bit.

Persily: It’s, in many ways, similar to

what I was doing with the federal gov-

ernment certainly: tracking the project;

make sure the public knows as much

stuff about what’s going on; representing

the Kenai Borough’s interest in the proj-

ect; talking with community groups;

talking with the public trying to serve as

a liaison between the project and the

public. An informed public is better than

an uninformed or ill-informed public.

This project is going to have a mas-

sive impact, if it

goes ahead, on the

Kenai Peninsula

Borough from the

liquefaction plant

storage tanks,

marine terminal, 30

miles of pipeline on

bottom of Cook

Inlet, pipeline on

both sides of Cook

Inlet. The way I look at it is, you will

have half the value, or more, within the

boundaries of the Kenai Borough.

There are other oil and gas issues that

I’m tracking for the borough: BlueCrest

Energy down by Ninilchik, just all the

activity in Cook Inlet. The mayor was

looking to have somebody on staff who

had expertise on oil and gas, and repre-

sents the borough, not just Alaska LNG,

all the activity down here.

I’ve known Mike Navarre since he

was a legislator and I was a reporter in

Juneau a long time ago. I bumped into

Mike in January when I was presenting

at a Kenai economic development con-

ference. By then, we knew the (coordi-

nator’s) office was closing; it was just a

matter of when.

Mike told me he had just recently

presented to the Borough Assembly a

proposal to create a new position for oil

and gas consultant special assistant, and

I should keep it in mind, which I did. He

and I talked the next couple of months

and I started on March 10.

Petroleum News: Weren’t you leadstaffer on some Cook Inlet legislationwhen you worked for (Legislative Budget& Audit Chair) Mike Hawker?

Persily: Right, the Cook Inlet Natural

Gas Recovery Act. I helped with legisla-

tion for Cook Inlet gas storage and some

initial tax credit discussion. But I should

also clarify it’s not just oil and gas. Mike

Navarre knows the fiscal situation is

going to be tight in years ahead, not just

for the state but for the municipality so

he wants me to work on some projects

as we look at the borough’s fiscal situa-

tion and as we look at the state’s fiscal

situation, what can the municipalities do

to help. So I’ll be working on those

issues too

Petroleum News: So he is also tap-ping into your experience as a deputyrevenue commissioner?

Persily: Right. So basically I’m doing

the same thing I’ve done the past 20

years as deputy revenue commissioner,

legislative aide, federal gas line coordi-

nator and putting all of that to work. It

pays to get a job where you don’t have

to learn anything new.

Petroleum News: So you’ve worked atjust about every level — state, federaland local — and with what you just cov-ered in mind, what would you like toaccomplish with this appointment?

Persily: Certainly the Kenai Borough

and most of its residents welcome the

LNG project. It’s not only going to have

good impacts on the community but traf-

fic certainly during construction, demand

on services, fire, police, more traffic. So

the more actively involved the borough

can be speaking up during FERC pro-

ceedings, working with the project,

working with DOT, the better everyone

will be. I can’t say I’m going to make

Alaska LNG possible. That implies I’ve

got some God-like powers. I don’t. I like

to make it as publicly manageable to the

residents here and help translate between

residents and the project development

team so the misunderstandings are kept

to a minimum, and also serve as a

resource for other communities along the

route and the state to the extent that I

can.

Petroleum News How engaged is thecommunity right now? Do you sense abuzz or is it too early for that?

Persily: No. I think the fact that

Alaska LNG has been buying property

and either purchased property outright or

executed options on property to more

than 550 acres of the 800 acres they are

trying to amass for the liquefaction plant

and marine terminal. You don’t keep that

a secret. People are sensing this has the

possibility over being very real.

So yeah, I’d say the buzz is building

but there is still that cynicism, that skep-

ticism that we’ve heard before that

you’re going to have to overcome. But

l G O V E R N M E N T

Same guy, different job, renewed energyPersily switches from federal to Kenai Peninsula Borough office while tapping into wells of diverse skills for projected AKLNG hub

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4 PETROLEUM NEWS • WEEK OF JUNE 21, 2015

Kay Cashman PUBLISHER & EXECUTIVE EDITOR

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l G O V E R N M E N T

Alberta jitters growNew government makes good on promise to raise income tax,expects to start review of royalties, climate policies later this year

By GARY PARKFor Petroleum News

A lbertans are getting their first taste

of life under a socialist government

and many in the province’s backbone

industry have decided they won’t stick

around for the appetizer to be served, let

alone the main course.

Rolling out a shortened legislative

agenda on June 15, the administration of

Premier Rachel Notley delivered on the

campaign promises that gained the New

Democratic Party a landslide victory on

May 5 by targeting an increase in corpo-

rate taxes to 12 percent from 10 percent,

hiking taxes on wealthier Albertans to 12

percent for those making more than

C$125,000 and 15 percent for those

above C$300,000.

The legislative outline also vowed to

eliminate political donations from corpo-

rations and labor unions.

But the government has delayed until a

fall session of the Legislature its plans to

review energy royalties and to unveil its

first budget, when the revenue impact of

the oil and natural gas sector’s slump will

be known.

All Notley would disclose was her

resolve to move ahead with a study of

royalties.

The government’s legislative outline

said only that the government will

“review how the people of Alberta ... will

be rewarded for the development of their

own energy resources.”

It also highlighted the need to “demon-

strate real leadership on the environment

and climate change” and urged a stronger

partnership with Canada’s other nine

provinces through a national energy strat-

egy.

Push expectedThe assumption among a wide cross-

section of observers is that Alberta will

join the push for an expanded carbon tax

above the C$15 per metric ton it imposes

on large emitters of carbon dioxide.

Notley said it’s important to move

carefully on changes to royalties or cli-

mate policy, but “we also know that we

can’t have it hanging over everyone’s

head indefinitely.”

That was an indirect acknowledge-

ment of stirrings that are already resulting

in further capital spending cuts by leading

explorers and producers, Canadian

Natural Resources and France’s Total,

and drastically slashing upstream jobs.

The Canadian Association of Oilwell

Drilling Contractors announced June 15

that the number of working days in the

drilling sector will see jobs shrink to

25,110 this year from 49,950 in 2014,

down another 2,500 from its prediction

six months ago.

Those estimates are based on an antic-

ipated 43 percent drop to 6,612 in the

number of wells drilled, with the average

number of rigs working nose-diving to

184 from a fleet of 768.

Royalty review citedCAODC President Mark Scholz linked

the downturn in activity to uncertainty

surrounding the pending royalty review,

along with uncertain natural gas demand

for LNG plants in British Columbia and

ongoing depressed commodity prices.

However, he said his organization is

“very much engaged” in discussions with

the Notley government, although “we

don’t really know where things are going

to be six months from now ... that is lead-

ing to additional uncertainty in a market

that probably doesn’t need it right now”

and spreads a cloud over future invest-

ment.

The realities are evident in Alberta

government auctions of exploration

rights, with non-oil sands bidding raising

C$136 million in the first 10 sales com-

pared with C$1.74 billion in the same

period of 2011.

Calgary-based investment banker

Peters & Co. forecast that drilling activity

will fall each quarter this year, reaching a

trough in the first quarter of 2016.

For those counting on hope over the

longer term, the Canadian Association of

Petroleum Producers offered a shred of

optimism earlier in May when it forecast

Canadian oil production (conventional

and from the oil sands) will rise to 5.3

million barrels per day by 2030 from the

current 3.7 million bpd, but that trails by

1.1 million bpd the industry lobby group

predicted a year ago.

Investor meetings postponedThe degree of pain and anxiety within

the overall production sector has been

swift, with CNR, which operates the

Horizon oil sands project and is one of

Canada’s top three conventional oil and

gas producers, postponing meetings with

investors until it can finalize spending

plans.

It said that due to uncertainty created

by the Alberta government capital will be

allocated “prudently in areas in which we

operate” until there is greater clarity sur-

rounding the province’s royalty, taxation,

environmental and greenhouse gas poli-

cies.

Total — the fifth-largest Western oil

see ALBERTA JITTERS page 5

By ALAN BAILEYPetroleum News

As part of a continuing investigation

into the pros and cons of reforming

the way in which the Alaska Railbelt power

transmission grid is managed, during a

May 27 meeting of the Regulatory

Commission of Alaska the commissioners

reflected on the various arguments for and

against reform. The state Legislature has

mandated that the commission investigate

whether there would be benefit in transfer-

ring the management of the grid to some

form of independent operator.

As part of its investigation, the commis-

sioners heard testimony from Antony Scott

from the Alaska Center for Energy and

Power. As previously reported by

Petroleum News, during a series of weekly

presentations Scott overviewed the com-

plex issues relating to grid management

reform. The commission has also received

written comments on the grid management

question.

Currently, ownership and operation of

the grid by five independent utilities leads

to inefficiencies in the use of power gener-

ation facilities on the grid. And, while the

grid infrastructure is aging and susceptible

to single points of failure, the utilities say

that they lack the financial resources to

undertake major grid upgrades.

Complex issuesBut, unifying the management of the

grid would raise some complex manage-

ment and commercial issues. So, would the

end result of unification justify the pain

involved in the transition from the current

management structure?

Commission Chairman Robert Pickett

commented that he would need to be con-

vinced that there would be tangible benefits

that would exceed the costs of reform

before he would support a reform proposal.

And although the grid as a whole may be

operating on a less than optimal basis, the

utilities have done a good job of “keeping

the lights on,” doing the best they can with-

in their own territories and using bilateral

agreements between utilities where neces-

sary, Pickett said.

However, although there is much uncer-

tainty over the scale of the benefits to be

gained from grid management reform,

there is a powerful argument in support of

a new management structure for the grid,

Pickett said. Pickett also made a compari-

son between the fragmentary nature of the

transmission grid operation and what used

to be the fragmented ownership of the

Cook Inlet gas pipeline infrastructure —

the pipeline system, which used to be char-

acterized by expensive and time-consum-

ing contention over tariff issues, has been

unified recently as a result of an ownership

change. The unification of the pipeline sys-

tem will prove beneficial for gas producers,

Pickett said.

Lack of consensusBoth Pickett and Commissioner T.W.

Patch commented on what they perceive as

a lack of consensus among the utilities over

what needs to be done. Patch added that he

did not see much willingness by individual

utilities to make sacrifices for the common

good. Moreover, since there are unresolved

issues regarding the allocation among the

utilities of savings gained from grid unifi-

cation, the value of unification remains

uncertain, he said. That raises questions

over whether creating some form of inde-

pendent operator for the grid would be the

most effective option for efficient electrical

transmission, Patch said.

On the other hand, the commission

needs tools such as the ability to oversee an

integrated energy resource plan and the sit-

ing of new power generation facilities, to

avoid some recent issues, such as the con-

struction of excess power generation

capacity, he said.

Commissioner Stephen McAlpine

expressed regret that some of the money

that had been invested recently in new

power generation capacity had not, instead,

been put into transmission upgrades. In the

current political climate, the likelihood of

the state Legislature granting additional

funds for transmission upgrades “is almost

nonexistent,” he said. Given that situation,

the three utilities at the center of the grid —

Chugach Electric Association, Municipal

Light & Power and Matanuska Electric

Association — may have to work more

cooperatively, with the more peripheral

utilities — Homer Electric and Golden

Valley Electric Association — operating

more independently, he commented.

However, several commissioners

expressed concern about the concept of

either the Legislature or the commission

trying to enforce reform against the utili-

ties’ wishes.

Commissioner Janice Wilson comment-

ed on the many studies that have been con-

ducted over the years into transmission grid

reform, with none of those studies ulti-

mately resulting in grid unification.

Both Wilson and Pickett commented on

the importance of the reliability of power

supplies, especially given questions over

the fragility of the grid and the lack of

redundancy in the current transmission

infrastructure. It would be useful to have

clarity over the commission’s authority to

regulate reliability issues across multiple

utilities, Wilson said.

The commissioners anticipate making

their determination on the transmission

grid management question after they fin-

ish accepting comments on the issue on

June 17. l

l U T I L I T I E S

Reflections on Railbelt grid issuesRCA commissioners comment on some of the issues relating to the potential for unified operation of the power transmission system

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company and a major investor in two

leading oil sands projects — warned the

government that raising taxes in the

already high-cost oil sands sector could

have a dramatic impact on spending.

Total Chief Executive Officer Patrick

Pouyanne said the oil sands already rank

near to the bottom in terms of return on

capital among global oil and gas plays.

He told the Globe and Mail that an

increased burden on oil sands operators

will “just accelerate the freezing of proj-

ects. I would not be inclined to invest

more there.”

Total is a partner with operator Suncor

Energy and Teck in construction of the

Fort Hills mine and phase two of

ConocoPhillips’ Surmont steam-injection

operation.

Whether these opening salvos will

prompt Notley to protect rather than

undermine Alberta’s greatest source of

wealth-creation will probably generate

even more summer heat pending details

of her government’s plan to turn election

pledges into reality. l

continued from page 4

ALBERTA JITTERS

The commissioners anticipatemaking their determination on the

transmission grid managementquestion after they finish

accepting comments on the issueon June 17.

By ALAN BAILEYPetroleum News

Anchorage electric utility Municipal

Light & Power is offering power

dispatch services to the other utilities on

the Alaska Railbelt transmission grid, to

evaluate the benefits to be gained from

the most efficient use of power stations

on the grid, James Trent, ML&P general

manager, told the Regulatory

Commission of Alaska on June 3. ML&P

has implemented a state-of-the-art com-

puter system for managing the dispatch

of electrical power and is offering to use

the system to help other utilities make

optimum use of power generation facili-

ties and to collect data on any resulting

economic benefits, Trent told the com-

missioners. The proposed arrangement

would last for one year, on a trial basis,

at no cost to the utilities that sign up.

To date four of the five Railbelt utili-

ties have concurred with implementing

the proposed service, Trent said.

At issue is the question of what is

referred to as “economic dispatch,” an

arrangement whereby hour-by-hour

power demand on an electricity grid is

met by preferentially operating the low-

est cost sources of energy.

Trent said that the computer system

that ML&P is now using to manage its

own economic dispatch is operating suc-

cessfully throughout the Lower 48 and is

also used in Europe. Under the proposed

one-year program ML&P would use the

system to provide utilities on a day-

ahead basis the information that they

need to decide which of their power gen-

erators to run, with the utilities retaining

the ability to choose whether to follow

the advice that the system provides. The

system would then track the cost savings

achieved, depending on the decisions

that individual utilities make, Trent said.

The system takes into account numerous

economic factors, he said.

At the end of the one-year trial it

would be possible to assess the effective-

ness of the computer system in managing

economic dispatch on the Railbelt grid,

Trent said. The hope is that the arrange-

ment would also enable the evaluation of

actual cost savings from economic dis-

patch, thus providing data for evaluating

future benefits to be gained from

improving the way in which the power

transmission grid is managed and operat-

ed.

Although, ideally, under an economic

dispatch arrangement, maximum use of

the most economic power source would

always be used, in practice this ideal

must be balanced against limitations in

the transmission system’s capacity to

carry power, and against the need to have

some redundant power available to

ensure the reliability of the power sup-

ply.

David LeVee, a power forecasting

consultant, told the commissioners that

the computer system that ML&P is using

takes into account the various constraints

in a power generation and transmission

system when determining the optimum

balance of power generation usage. It is

possible to specify the constraints, so

that the system can determine when

transmission loads, for example, would

hit the transmission limits, he said.

There has been a multi-year debate in

Alaska over whether or how to change

the manner in which the Railbelt trans-

mission grid is managed and operated, to

address the current grid’s shortcomings

and ultimately facilitate economic dis-

patch. In the latest phase of this debate

the state Legislature has tasked the com-

mission with making a recommendation

on whether management of the grid

should be transferred to some form of

independent operator.

Trent told the commissioners that,

although ML&P has been actively

involved in discussions over various

models for the unified operation of the

Railbelt grid, the utility has been unable

to make an effective business case for

adopting any of the models proposed.

However, the implementation of eco-

nomic dispatch is embedded in all pro-

posals, he said. ML&P’s proposed

arrangement would provide the opportu-

nity for at least some economic savings

from the more efficient use of Railbelt

power generation, Trent told the com-

missioners. l

6 PETROLEUM NEWS • WEEK OF JUNE 21, 2015

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l U T I L I T I E S

ML&P proposes

Railbelt power

dispatch solutionOffers service to utilities to help make best use of availableelectricity generation facilities on the Railbelt transmission grid

LAND & LEASINGNo substantial new info decisions

The Alaska Division of Oil and Gas has issued a decision of no substantial new

information for the state’s fall 2015 Beaufort Sea, North Slope and North Slope

Foothills areawide oil and gas lease sales.

The division issued a call for new information in March and received comments

from the Alaska Regional Office of the National Park Service, which commented on

the North Slope Foothills lease sale area’s shared boundary with the Gates of the

Arctic National Park and Preserve. Gates of the Arctic is south of the Foothills areaw-

ide lease sale.

The division said the National Park Service commented that oil and gas activities

are incompatible with the purposes of the park and preserve and said effects on park

and preserve resources and values from oil and gas activities on adjacent state lands

should be evaluated and factored into leasing decisions and requested the opportunity

to review lease sale information for lands near the boundaries of the park and preserve.

The director’s response to those comments was that mitigation measures in the

final finding along with state and federal requirements are sufficient to protect park

resources and said it would not supplement the finding with new lease sale stipula-

tions. NPS also expressed concerns about drainage of resources from park and pre-

serve lands, and the division said Alaska Oil and Gas Conservation Commission

statutes protect correlative rights.

The division also said agency and public information was requested at the time the

2011 final finding was made for the sale, and no comments were made at that time

about areas of special concern requiring mitigation. The division also said no specific

substantial new information was offered in the NPS comments.

—PETROLEUM NEWS

Call today: 907.522.9469

By GARY PARKFor Petroleum News

C hances that the Canadian oil patch

could come to life with a round of

merger-and-acquisition deals, providing

help to a reeling oil market, is an ongoing

topic that lacks any sense of clarity.

So far transactions this year have been

only intermittent, further inhibited by the

absence of any sign from the Canadian

government that it might relax rules on

acquisitions by foreign state-owned com-

panies.

Market sources say that hard line may

have put a clamp on a months-long effort

by debt-burdened Legacy Oil + Gas to find

a buyer that reportedly attracted interest by

a state-owned enterprise, believed to be

Chinese, who have retreated from the lime-

light over the past three years.

Word from the street pointed to a “non-

binding” bid that was worth more than the

successful offer by Crescent Point Energy

of C$563 million for Legacy, plus an

assumption of C$967 million in debt,

which valued Legacy shares at C$2.85,less

than 30 percent of the company’s 52-week

high of C$10.03.

If concluded, the deal will boost

Crescent Point’s current production of

152,500 barrels of oil equivalent per day by

22,000 boe per day (82 percent oil and liq-

uids), of which more than 15,000 boe per

day is from Bakken plays in Saskatchewan,

Manitoba and North Dakota.

The assets include 1.64 million acres, of

which 336,000 acres are in southeastern

Saskatchewan; 940 net internally identified

drilling locations; and proved plus proba-

ble reserves of 102.7 million boe, repre-

senting a reserve life index of 14.1 years

based on output of 20,000 boe per day.

Activist investment firmThe deal came two months after activist

investment firm FrontFour Capital Group

arrived on the scene, acquiring 6.8 percent

of Legacy’s shares and demanding three

board seats along with improved corporate

governance.

Zachary George, who leads FrontFour,

said the Crescent Point offer was a win for

his firm, which acquired its Legacy hold-

ings for C$2 a share, noting that there is

significant interest in Legacy’s

Saskatchewan acreage.

Whatever money might have been put

on the table for Legacy, the company said

in a circular the late overture would have

been “subject to a number of Canadian and

foreign regulatory approvals, which would

introduce material transaction risk and

delay.”

Although details are scarce, it is

believed the Chinese SOE that approached

Legacy was not among Beijing’s power-

houses, such as CNOOC, Sinopec or

PetroChina. Even so, it suggests interest

remains strong in Canadian energy assets,

despite the Canadian government’s virtual

ban on foreign SOEs taking control of oil

sands projects.

Catharine Sterritt, managing director,

global equity, at the Bank of Nova Scotia,

said SOE investments in Canada have “not

worked out” as planned, consuming more

capital and time than anticipated.

Otherwise, deal-making has been

restricted to small- and mid-sized produc-

ers, such as Whitecap Resources’ C$517

million cash and share purchase of

Beaumont Energy, a Saskatchewan light oil

producer; Torc Oil’s C$430 million

takeover of Surge Energy; and

Tourmaline’s C$257 million acquisition of

Perpetual Energy, which operated in the

Alberta Deep Basin.

Only C$5 billionThe value of corporate and asset deals in

Canada’s energy sector tallied about C$5

billion for the first five months of 2015,

compared with C$20 billion in the first half

of 2014.

Adam Waterous, co-head of global

equity at the Bank of Nova Scotia, told the

Globe and Mail the big deals that have

occurred over the past three years were

“really the weak being culled from the

herd. We don’t have that situation today.”

Suncor Energy and Encana have issued

word that they are in no hurry to complete

transactions, with Encana Chief Executive

Officer Doug Suttles suggested some com-

panies will survive rather than get swal-

lowed up because capital markets have

been more inclined to issue debt and equi-

ty.

Crescent Point Chief Executive Officer

Scott Saxberg holds the view that if

Alberta’s New Democratic Party govern-

ment changes its royalty regime that will

open the door to “companies such as our-

selves to buy Alberta-based companies for

discount value.” l

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

M&A uncertainty prevailsHopes for a gusher of deals in Canada lack clarity; signs from Crescent Point-Legacy deal point to interest in energy assets by SOE

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Better.

By KRISTEN NELSONPetroleum News

L egislators got a required update on the

Alaska LNG Project June 16, hearing

from the project manager, commercial

group members and the administration.

The presentation was made to a joint

meeting of the House and Senate

Resources committees held in Nikiski,

where legislators also had an opportunity

to view the proposed site of the liquefied

natural gas plant. An update on the project

is required every four months.

Steve Butt of ExxonMobil, the Alaska

LNG project manager, said $294 million

has been spent to date, $187 million on the

preliminary front end engineering and

design phase of the project.

While it’s not part of the Alaska LNG

project, natural gas from Point Thomson

on the North Slope will be necessary for

the project, and Butt said the third well for

the initial production system at the field is

near completion. Point Thomson will ini-

tially produce condensate, with natural gas

reinjected into the field; new wells and gas

processing facilities will need to be built at

the field. Prudhoe Bay, expected to pro-

vide the majority of natural gas for

AKLNG, will also require modifications

and new facilities which will be managed

by BP, the unit operator.

Western Cook Inlet routeAmong the work completed, Butt said,

is a technical rationale for the western

route in Cook Inlet. He said the route, des-

ignated “RevB,” is complete, and aligned

with the Alaska Gasline Development

Corp., which is working on a smaller alter-

nate line in the event AKLNG fails to

move forward.

He said that before detailed work was

done the preference was for the eastern

route because that would not require cross-

ing the Susitna River.

But, he told legislators, once the Susitna

is crossed construction is pretty easy, with-

out the challenges presented in the mouth

of Knik Arm — on the eastern route —

where silts are laid down in such volume

that the weight settling on a pipeline could

be a problem.

The technical rational for the western

route includes:

•A shorter overall pipeline length than

the eastern route;

•The onshore portion of the western

route avoids Captain Cook State Park, the

Susitna Gunnery Range, agricultural areas

and critical wetlands;

•Comparable onshore construction

costs and schedules to the eastern route;

•Significantly fewer offshore construc-

tion challenges, including: closer to deeper

water, lower current, fewer shipping inter-

ruptions, less protected species impact,

avoiding Chugach Electric Association

buried power cables; and

•Relatively stable seabed as opposed to

active seabeds on the eastern route.

Offtake application in JulyBill McMahon of ExxonMobil, pre-

senting for the commercial team, said the

project hopes to be in a position to put in a

formal application to the Alaska Oil and

Gas Conservation Commission for gas off-

take at Prudhoe Bay in July, and have a

final ruling on Prudhoe Bay offtake before

the end of the year.

On the issue of agreements which need

to be reached, McMahon said ExxonMobil

believes good progress is being made.

Dave Van Tuyl of BP said the challenge is

that all agreements are substantive and

time is limited, but said BP has committing

to putting the necessary resources to work

on each agreement to get them done, with

separate teams working on them, so

they’re not all going through the same fun-

nel.

Darren Meznarich of ConocoPhillips

said they’re working hard on agreements

and hoped they would have made more

progress by now; the focus, he said, is on

problem solving, trying to find solutions.

Vincent Lee of TransCanada said the

firm transportation services agreement

with the state was the most relevant to

TransCanada, and current discussions are

on hold because the administration is look-

ing at different options. TransCanada holds

the state’s interest in the pipeline portion of

the project, and pays the state’s contribu-

tion for that work. Under the FTSA, the

state would agree to pay TransCanada for

shipment of natural gas on TransCanada’s

share of the pipeline, reimbursing

TransCanada for the monies it puts into the

project by paying for gas shipment. Gov.

Bill Walker has indicated that he wants the

state to exercise its option to buy out

TransCanada, an option it can exercise by

the end of this year.

What’s most important?Asked where the Legislature should be

focused, McMahon said property tax legis-

lation, the payment in lieu of taxes; review

and ratification of fiscal contracts; and any

commercial agreements what require leg-

islative agreement.

Dan Fauske, president of the Alaska

Gasline Development Corp., said to him

the gas balancing agreements were the

most daunting. He said the agreements

mentioned would benefit the project, but

without gas balancing there is no project.

We need to get that done, he said, calling

progress slow.

Van Tuyl said another item, in the

purview of the administration, is a royalty

in kind election, which is something the

commissioner of the Department of

Natural Resources must do to allow the

state to take royalties in kind, making up a

portion of the 25 percent state gas owner-

ship, the remainder of which would come

from the state taking its production tax in

gas.

Constitutional amendment?Asked if a constitutional amendment

would be needed to allow fiscal certainty

for the project, Van Tuyl said BP is confi-

dent with existing language in the constitu-

l N A T U R A L G A S

Legislators get update on Alaska LNGProject work on schedule for 2016 FEED decision; fiscal certainty from state needed; continuing role of TransCanada uncertain

8 PETROLEUM NEWS • WEEK OF JUNE 21, 2015

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see LNG UPDATE page 14

page10

Tangen: Court says MLUP can be functionally Irrevocable

www.MiningNewsNorth.com The weekly mining newspaper for Alaska and Canada's North Week of June 21, 2015

NEWS NUGGETSCompiled by Shane Lasley

l R A R E E A R T H E L E M E N T S

Unga delivers high-grade gold-silverRedstar Gold Corp. June 11 reported multi-ounce gold

intercepts from the first two holes of a recently completed

eight-hole drill program on the Shumagin prospect at its

Unga gold project on the Alaska Peninsula. Hole 15SH011

cut 1.9 meters grading 5.89 ounces per ton gold and 2.4 oz/t

silver over 1.9 meters. Hole 15SH012 cut three intercepts:

1.03 oz/t gold and 6.1 oz/t silver over 2.0 meters; 0.49 oz/t

gold and 5.3 oz/t silver over 3.0 meters; and 3.88 oz/t gold

and 12.3 oz/t silver over 0.7 meters. “These are the drill

results from a new management team, and these results con-

firm our optimism for the Unga Gold Project, and the

Shumagin area specifically. We intersected mineralization

where we expected, with high-grade gold and silver grades,”

said Redstar Chairman Jacques Vaillancourt. The phase-1

program at Unga was designed to target various structural

elevations of the Shumagin vein system while systematically

testing for continuity of mineralization and obtaining geo-

logical constraint within areas of existing known high-grade

mineralization through infill drill holes, including the holes

reported above; and exploratory step-out drilling of the vein

system at depth and along strike to the northeast by about

100 meters through four step-out drill holes. Results from

the remaining six holes are pending. Redstar said a phase-2

drill program planned for later 2015 will maintain a focus on

the Shumagin prospect concurrent with exploration of other

known high-grade gold targets located within the Unga gold

project.

Graphite Creek claims conflict settledGraphite One Resources Inc. June 11 reported that its

wholly owned subsidiary, Graphite One (Alaska) Inc. has

come to an agreement with Ronald Sheardown for 28 Alaska

state mining claims covering the same lands purchased by

Graphite One in January 2012. This provides the company

ownership of both the jun-

ior and senior state mining

claims that overlap and

surround the 24 unpatented

federal claims that it leased

from Kougarok LLC. In

exchange for the claims,

Graphite One has agreed to

pay US$50,000 and issue 3

million common shares to

Sheardown. Sheardown

also will receive a royalty

interest equal to 1 percent of the net smelter returns received

on G1 Alaska claims, subject to Graphite One’s option to

purchase the royalty for US$500,000 at any time within 36

months following the start of mine production. Graphite One

Bottom of Formalso retained Sheardown to sit on its adviso-

ry board for three years. As part of this position, Sheardown

has been granted stock options to purchase 1 million

Graphite One common shares at C13 cents per share.

Graphite One’s Graphite Creek property now includes the 28

state mining claims acquired by G1 Alaska in 2012 plus the

claims acquired from Sheardown, 77 state claims staked by

G1 Alaska in 2012 and 24 leased federal claims. “With this

agreement, Graphite One (Alaska) now fully controls, free

of any conflicting locations, the right to possess and extract

100 percent of its identified resource,” said Graphite One

CEO Anthony Huston. “The company will also benefit from

being able to draw on Ron Sheardown’s extensive experi-

ence in major development projects, and he will be a great

asset to our board and management. Sheardown has been

see NEWS NUGGETS page 11

Ahead of the REE crowdUcore’s separation process draws investor; explorer eyes Bokan feasibility

By SHANE LASLEYMining News

Ucore Rare Metals Inc.’s exploration endeav-

ors are proving successful – not only in

expanding the heavy rare earth elements-enriched

deposit at the Bokan Mountain Project in

Southeast Alaska, but in discovering new tech-

nologies that advance rare earth refinement into

the 21st Century.

Hoping to cash in on this success, a “high net-

worth” American investor recently tendered a

US$1 million down payment toward royalties

offered by Ucore.

These royalties will not

come from the future sale of

rare earths mined at Bokan

Mountain. Instead, they will

derive from the sale of prod-

ucts and services related to

SuperLig Molecular

Recognition Technology, a

proprietary rare earths and

specialty metals separation

method that Ucore is

involved with developing.

All told, the un-named investor has agreed to

pay US$4 million in exchange for royalties associ-

ated with the cutting-edge REE separation technol-

ogy.

“The investment is favorable for Ucore since

there is no debt burden, and is prospectively non-

dilutive, given that shares will not be issued by

Ucore upon closing,” said Ucore President and

CEO Jim McKenzie. “What’s more, the transac-

tion is a vote of confidence from a major investor

in the remarkable growth potential of MRT, as well

as an endorsement and financing milestone for

Ucore, as it transitions towards near-term revenue

status and vertical integration.”

Separate technologyIBC Advanced Technologies, a Utah-based

company that develops and manufactures molecu-

lar recognition technology for a broad range of

applications, has successfully applied the tech-

nique to separating notoriously tightly interlocked

rare earth elements.

The MRT process is designed to bind selective-

ly with ions based on multiple parameters such as

size, chemistry, and geometry.

Using a pregnant leach solution prepared from

material taken from Dotson Ridge deposit at

Bokan Mountain, IBC Advanced Technologies

developed a three-step process for creating nearly

pure rare earths.

On June 16, Ucore announced that Dr. Reed

Izatt, a chemist and one of the founding principles

of IBC Advanced Technologies, and Steven Izatt,

president and CEO of IBC, would be joining

Ucore’s advisory board.

“With Ucore’s expanding focus on metals sepa-

ration technologies, the insights provided by Dr.

Reed Izatt and Mr. Steven Izatt, combined with the

benefit of IBC’s experience as the global leader in

MRT applications to the mining industry, will be

invaluable,” explained McKenzie.

In early March, Ucore reported that IBC’s MRT

process had separated all the individual rare earth

elements found at Bokan Mountain into salts of

greater than 99 percent purity, except for samarium

and gadolinium, which remained bound together.

Samarium and gadolinium have now been sep-

arated into individual salts, each with 99.2 percent

purity.

Not only did the process create pure salts across

the entire suite of rare earths, it did so while recov-

ering more than 99 percent of the REEs available

in the pregnant leach solution.

“We look forward to completing pilot-scale

testing of this promising nano-technology,” said

McKenzie.

Upon delivery of a fully functional pilot plant,

Ucore has agreed to pay IBC US$2.9 million for

rights to the potentially sector-changing technolo-

gy.

Under an agreement announced in March,

Ucore will hold a 60 percent interest in a joint ven-

ture with IBC to market and sell SuperLig

Molecular Recognition Technology for rare earth

separation and recycling applications, as well as

tailings processing applications.

“Perhaps most importantly, our licensing

arrangement includes the application of SuperLig

technology to the world recycling and tailings pro-

cessing sector – both for the recovery of rare earths

and all other metals,” McKenzie said at the time.

The US$4 million from the yet-to-be-named

investor will help pay for the rights.

In exchange, the investor will be granted royal-

ties equal to five percent of gross sales from the

first MRT installation or installations, payable

until the investment is recouped; and a net smelter

royalty equal to 2 percent of the net sales from

Ucore’s first C$50-million-per-year molecular

recognition technology client.

The investor has the option to increase the roy-

alty by up to 0.5 percent by putting up another

US$1 million by Aug. 13. An option to trade in the

royalties for Ucore shares is also on the table.

Upgrading BokanIn addition to finding new and improved ways

to separate rare earths, Ucore’s exploration has sig-

nificantly upgraded and expanded the REE

resources at the Dotson Ridge deposit of its Bokan

Mountain project.

This expansion is the result of a 4,000-meter

drill program completed last year.

The smaller of two rigs drilling at Bokan during

2014 focused on upgrading inferred resources to

the indicated category by infill drilling of the rare

earths deposit.

Of the 12 infill holes drilled, 10 cut significant

mineralization. One hole, LM 14-142, cut multiple

intercepts exceeding 1 percent TREO. Highlights

see UCORE PROGRESS page 11

“We look forward to completing pilot-scale testing of this promising nano-

technology.” —Jim McKenzie, presidentand CEO, Ucore Rare Metals Inc.

JIM MCKENZIE

This provides the companyownership of both thejunior and senior state

mining claims that overlapand surround the 24

unpatented federal claimsthat it leased from

Kougarok LLC.

10NORTH OF 60 MINING PETROLEUM NEWS • WEEK OF JUNE 21, 2015

By J. P. TANGENSpecial to Mining News

“For now we see through a glass,darkly….” I Corinthians 13:12

On May 29, 2015 the Alaska Supreme

Court handed down two opinions

relating to the Pebble Project: The first

reversed the Superior Court’s holding in

Nunamta Aulukesti, et al, v. State, et al,

regarding the revocability of

Miscellaneous Land Use Permits, or

MLUPs, and the second reversed the

lower court’s award of costs and attorney’s

fees against the plaintiffs in the Nunamta

case.

If obfuscation is integral to the stereo-

type of the legal profession, certainly the

Nunamta and its sister decision ring true to

that precept. In the simplest terms, the

court held that MLUPs can, under some

circumstances, convey an interest in state

land. Where that insight becomes blurry,

however, is in knowing in advance when

that will occur. The court’s opinion relied

heavily upon two earlier decisions,

Northern Alaska Environmental Center v.

State, (2 P.3d 629 (Alaska 2000)) (which

also gave no real clue as to when to expect

“functional irrevocability” to engage in the

permitting process) and SOP, Inc. v. State,

(310 P.3d 962 (Alaska 2013)), where the

court differentiated between a “license,”

defined as a permit that is revocable at the

will of a grantor and an easement, which is

a disposal of state land requiring public

notice under Article VIII, section10 of the

Alaska Constitution.

Being careful not to hold “that all

MLUPs are disposals of interests in state

land” the court made it clear that “[p]ublic

notice is constitutionally required only

when a MLUP is functionally irrevoca-

ble.”

The court then proceeded to tell us that

there are two tests for functional irrevoca-

bility. The first test arises when a threshold

investment has been made. In the case of

the Pebble Project, it appears that the

threshold amount might be $300 million.

The court observes that “[t]he potential

loss of an investment of this magnitude

could deter DNR from cutting short PLP’s

exploration process by revoking … or not

renewing a permit” issued under 11 AAC

96.040 after a determination that the revo-

cation is in the state’s interest.

According to the court, “where large

sums have been invested, the government

is effectively forced to honor the full term

of the permit….” This insight should give

comfort to future investors in Alaska who

will surely prefer to have the security of

their investments established before spend-

ing the money as opposed to afterward, as

the regulation now suggests.

The second test, which is somewhat

more complicated, relates to whether plug-

ging boreholes and burying non-toxic

drilling waste, as required by permit stipu-

lations, renders the issuance of a MLUP a

conveyance. Presumably, there is a quanti-

tative aspect to this test as well; but noth-

ing can be gleaned from the opinion.

Clearly, if buried drilling mud or borehole

plugs are “lasting alterations to the land,”

then the ashes from any fire, the field dis-

posal of any human waste or the exhaling

of carbon dioxide when working around a

drill rig could qualify.

Of course, because MLUPs are integral

to mineral exploration on state land, min-

ers (as well as anyone else doing anything

requiring a permit) will probably have to

be aware of the Nunamta decision. The

State is undoubtedly going to have to redo

the regulations to at least clarify where the

de minimis limit is, assuming there is one.

Notably, public notice is not necessarily

the equivalent of “public interest” determi-

nation; however, for public notice to be

effective, the permitting timeline will be

extended and the demands on the

Department of Natural Resources will

increase, all at a somewhat inconvenient

time in our state’s history.

The second decision handed down by

the court on May 29 related to the award

of costs and attorney’s fees in the Nunamta

case. In the first decision, the court recited

that “[a]ll the permits that were challenged

in this case have expired. As to them, this

case is moot…. [b]ut still pending are pro-

ceedings in which the State and PLP are

seeking large awards of attorney’s fees and

costs. Since these awards depend on a pre-

vailing party determination, this case

remains a live controversy for the purpose

of determining which party prevailed.”

The court then declared Nunamta and

the other plaintiffs below were the prevail-

ing party and remanded the application to

the Superior Court, which had previously

found the case frivolous, for determining

what they are entitled to recover under the

Supreme Court’s decision.

Despite the efforts of the state

Legislature to circumscribe the ability of

purportedly public interest claimants to

escape liability for their litigious predilec-

tions, it appears that the state may be

obliged to fund the war chest of the envi-

ronmentalists once again, the budgetary

shortfall notwithstanding.

Some versions of the Bible translate the

Greek word “agape” as used in Saint

Paul’s first epistle to the Corinthians to

mean something between “charity” and

“love;” however, whether the Supreme

Court loves environmentalists or is sim-

ply charitable to them, I confess, I still

see through the glass only darkly. l

l O P I N I O N

Supreme Court reminds us of St. PaulA MLUP might be functionally irrevocable, giving you an interest in state land, if you spend enough money or you plug a borehole

Mining & thelaw

The author,J.P. Tangen hasbeen practicingmining law in J.P. TANGENAlaska since 1975. He can be reached atjpt@jptangen.com or visit his Web site atwww.jptangen.com. His opinions do notnecessarily reflect those of the publishersof Mining News and Petroleum News.

WHATEVER

WHENEVER

WHEREVER

judypatrickphotography.comCreative photography for the oil & gas industry.

907. 258.4704

11NORTH OF 60 MINING

PETROLEUM NEWS • WEEK OF JUNE 21, 2015

Shane Lasley PUBLISHER & NEWS EDITOR

Rose Ragsdale CONTRIBUTING EDITOR

Mary Mack CEO & GENERAL MANAGER

Susan Crane ADVERTISING DIRECTOR

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Bonnie Yonker AK / INTERNATIONAL ADVERTISING

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ADDRESS • P.O. Box 231647Anchorage, AK 99523-1647

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call (907) 522-9469 or sign-up online at www.miningnewsnorth.com.

Several of the individualslisted above are

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North of 60 Mining News is a weekly supplement of the weekly newspaper, Petroleum News.

NORTHERN NEIGHBORSCompiled by Shane Lasley

Amaruq drilling exceeds expectationsAgnico Eagle Mines Ltd. June 10 reported that results from the 2015 phase

1 exploration program at the Amaruq gold project in Nunavut exceeded expec-

tations. Drilling during this program filled a gap under Whale Lake with signif-

icant gold grades and good widths, including 19.8 grams per metric ton gold

(capped) over 5.0 meters in hole AMQ15-187; and 15.9 g/t gold (capped) over

14.6 meters in hole AMQ15-181. The drilling also confirmed a new gold struc-

ture about 100 meters north of the Whale Tail deposit, including 6.1 g/t gold

(capped) over 4 meters and 9.7 grams g/t gold (capped) over 3.8 meters in hole

AMQ15-177. In February, Agnico Eagle announced an initial inferred mineral

resource for Amaruq of 6.6 million metric tons at 7.07 g/t (1.5 million ounces)

gold. The company said the Whale Tail infill drilling suggests a larger resource

is to come. More than 102 holes (27,750 meters) of the first phase 2015

Amaruq drill program were completed as of May 31, when seven drill rigs

were in operation on the project. Most of this drilling has been to fill the for-

mer gap under Whale Lake, which is now successfully completed to a depth of

200 meters. To date the Whale Tail deposit has been defined over about 1,200

meters of strike and extends from surface to a depth of more than 370 meters

depth. It remains open at depth and to the southwest. The phase-1 program

also included reconnaissance drilling at Mammoth Lake and the area between

the R zone and Whale Tail. Agnico says it expects three drills to be added to

the program by the end of June. Agnico Eagle has a 100 percent interest in the

Amaruq project, which consists of 114,761 hectares (283,580 acres) of Inuit-

owned and federal crown land, about 50 kilometers (30 miles) northwest of the

Meadowbank mine.

Milestone permit for Red Chris issuedImperial Metals Corp. June 16 reported the receipt of an amended British

Columbia Environmental Management Act Permit for its Red Chris copper-

gold mine in northwestern British Columbia. The amended permit, which the

B.C. Ministry of Environment issued to Red Chris Development Co. Ltd. on

June 12, replaces the previously issued short-term authorization. This permit

allows the mine to discharge tailings into the tailings storage facility and dis-

charge water from the facility subject to water quality guidelines. Imperial said

the amended permit is an important milestone for Red Chris as it ensures the

mine can operate on a continuous basis, subject to the conditions of the permit.

Akie drilling aims below Cardiac CreekCanada Zinc Metals Corp. June 12 reported that crews have been mobilized

to the Akie zinc-lead-silver property in northeastern British Columbia in prepa-

ration of a planned 5,000-meter drill program primarily targeting the lower ele-

vations of the indicated and inferred sections of the mineral resource at Cardiac

Creek. The company said the central core represents the highest grade and

thickest area of the deposit and the down-dip extent of this core will be the pri-

mary target area for the 2015 drilling. Other work planned for the 2015 season

includes field assessment of high-priority geophysical targets identified through

ongoing airborne gravity data interpretation; and focused soil geochemistry in

select areas. Environmental studies, including surface and groundwater sam-

pling, also are ongoing. l

Contact North of 60 Mining News:Publisher: Shane Lasley • e-mail: publisher@MiningNewsNorth.com

Phone: 907.229.6289 • Fax: 907.522.9583

from this hole include 2.42 meters of 1.03

percent TREO, 2.76 meters grading 1.65

percent TREO, 3.37 meters grading 1.9

percent TREO and 2.88 meters grading

1.12 percent TREO.

The larger rig drilled five holes aimed

at expanding the resource to depth. The

best intercept of this drilling was 3.0

meters averaging 0.755 TREO, of which

43 percent were HREOs, in hole LM14-

143.

Incorporating these holes in the calcu-

lations, the deposit now contains an esti-

mated indicated resource of 4.79 million

metric tons averaging 0.6 percent (63.54

million pounds) total rare earth oxides, a

roughly 63 percent increase over the 2.94

million metric tons of indicated resource

included in a 2013 estimate.

Additionally, the deposit has 1.05 mil-

lion metric tons of inferred resource aver-

aging 0.6 percent (13.96 million lbs.)

TREO.

About 39 percent of the TREO in both

categories are the higher valued heavy

rare earths.

The updated resource provides some

of the final bits of information for

Ausenco Engineering Canada Inc. to

complete a feasibility study for Bokan

Mountain.

The feasibility study builds upon a

preliminary economic assessment com-

pleted by Tetra Tech in 2012 that outlines

an underground mine feeding 1,500 met-

ric tons of ore to a 750-metric-tons-per-

day mill and a state-of-the-art processing

facility at Bokan Mountain.

The operation outlined in the PEA

envisions the production of about 2,500

tons of rare earth oxides per year during

the first five years of full production;

including an annual output of 105 tons of

dysprosium oxide, 15 tons of terbium

oxide, and 568 tons of yttrium oxide.

With the feasibility study in the works,

Ucore has already initiated permitting

and the company plans to have a plan of

operations submitted by early 2016.

Ucore believes the exploration and

development of its heavy rare earth-

enriched Bokan Mountain project, along-

side the cutting-edge REE refining tech-

nology separates it from other rare earth-

focused companies in North America.

“This resource upgrade, together with

our recent advances in molecular recogni-

tion technology for refining applications,

makes for a compelling mine-to-metal

story at Bokan,” observed McKenzie. l

continued from page 9

UCORE PROGRESS

involved in mineral exploration in Canada, USA, Greenland, Russia and Africa

for more than 50 years. He is recognized as the co-discoverer (with Murray

Watts) of the Baffinland Iron Mines Corp.’s Mary River deposit in Nunavut and

was part of the team that discovered the Asbestos Hill and Raglan Nickel

deposits in Quebec and the Black Angle Mine in Greenland.

NovaCopper-Sunward merger approvedNovaCopper Inc. June 16 reported that its proposed acquisition of Sunward

Resources Ltd. received overwhelming approval by the shareholders of each

company at their respective shareholder meetings. Under the terms of an arrange-

ment announced in April, each shareholder of Sunward will receive 0.3 of a

NovaCopper share for each common share of Sunward held. Some 99.36 percent

of the shares represented at the NovaCopper meeting were voted in favor of the

issuance of common shares of NovaCopper in connection with the arrangement.

Similarly, 99.98 percent of the shares represented at the Sunward meeting were

voted in favor of the arrangement. Sunward has roughly 142.33 million shares

outstanding, making the deal worth about US$27.6 million. At the end of 2014,

the Colombia-focused exploration company had US$20.95 million in cash and

cash equivalents. Combined with the nearly US$4 million NovaCopper already

had in its coffers, the merged entity would have plenty of cash to complete a fea-

sibility study for the Arctic deposit, the next step toward developing mines at the

Upper Kobuk Minerals projects in Northwest Alaska.

First-pass Hilltop exploration completeNorthern Empire Resources Corp. and Sonoro Metals Corp. June 15 said they

have completed the first phase of field work at the Hilltop Gold project located

some 45 miles southeast of Fairbanks. The phase-1 program, which began in

May, included 8.2 miles (13.2 kilometers) of road improvements to provide

access to priority zones; eight trenches excavated and mapped over a total strike

extent of 213 meters; six test pits completed in areas with prospective geology;

228 rock samples collected from trenches and test pits; 397 soils collected across

the Hilltop block; and initial prospecting and reconnaissance work. “We believe

significant discovery potential exists in the Richardson Gold District, particularly

on this large land package at Hilltop,” said Northern Empire Chairman John

Robins. “We also are highly impressed with Alaska as an exploration jurisdiction.

The combination of ease of permitting, excellent access, ample power, and sup-

portive and competent local expertise reduces risks and costs and provides excel-

lent upside for investors.” The companies expect to receive analytical results

from the soil and rock sampling programs in early July.

Prioritizing Elephant Mt. gold targetsEndurance Gold Corp. June 11 said the summer 2015 exploration program at

its Elephant Mountain gold property in Interior Alaska has begun. Previous explo-

ration has confirmed an intrusive-hosted target encompassing two gold-arsenic

soil and rock sample anomalies (the North and South Zone targets) and an

induced polarization chargeability anomaly (the Central Zone target) lying

between the two soil anomalies that has never been drill tested. Elephant

Mountain is located in an active placer gold mining region about 76 miles (123

kilometers) west of Fairbanks and can be accessed by road and all-terrane vehicle

trails from the mining community of Eureka. Crews are currently clearing access

trails from Eureka, which will be followed by the auger drilling program. l

continued from page 9

NEWS NUGGETS

12NORTH OF 60 MINING PETROLEUM NEWS • WEEK OF JUNE 21, 2015

By KRISTEN NELSONPetroleum News

A joint meeting of Alaska’s House and Senate

Resources committees, held in Kenai June 17,

heard an overview on oil and gas tax credits from the

Alaska Department of Revenue, an analysis by consult-

ants enalytica and views from some of the state’s smaller

producers and explorers on the role of credits in attract-

ing investment.

Revenue Commissioner Randy Hoffbeck told legisla-

tors the administration did not take a position on tax

credits this year because it did not want to get into a

debate on the issue. He said credits are an integral part of

the financing and economics of projects and said the

administration would not have unilaterally tried to reduce

credits. Going forward, he said, the administration will

engage in a discussion on the best way to look at credits,

but, he said, it would not be proper just to cut them off.

Ken Alpert, director of Revenue’s Tax Division, gave

legislators an overview of tax credits, and said since the

2007 transition into the PPT oil and gas tax system, some

$7.4 billion in credits have been used, $4.3 billion against

tax liability by those with production and $2.2 billion in

refunded credits by new producers and explorers devel-

oping new fields.

On the current state deficit, Alpert said the main rea-

son for the deficit is that the price of oil is half what it

was. He said taxes go down faster than prices when

you’re taxing on net profits. Alpert also said the state is

not losing money on oil, the state’s cash flow issues are

the result of policy — credits are fixed and tied to spend-

ing, he said, while taxes are tied to price.

Weaker fundamentalsJanak Mayer and Nikos Tsafos of enalytica, analysts

contracted by the Legislative Budget and Audit

Committee, analyzed oil prices and government vs. pro-

ducer take based on prices.

Tsafos said the oil price drop was due to weaker fun-

damentals: U.S. production has grown over the past five

years and that growth was initially offset by unplanned

outages elsewhere in the world caused by events such as

civil war in Libya and sanctions on Iran.

But in 2014, he said, some worldwide production

began to come back on, while U.S. production continued

to boom, and expectations for worldwide demand started

to drop. And OPEC decided to let the market show what

the price should be, at what price do American producers

start to go bankrupt?

Low oil prices are creating a response in activity in the

U.S., Tsafos said, with the rig count dropping, but pro-

duction hasn’t crashed because not all rigs or wells are

equal — you can cut 20-30-40 percent of rigs and only

have a minor impact on production, because those cuts

are on the most marginal projects.

Impact on stateThe big picture for state revenues and credits, Mayer

said, is that a drop in the West Coast price for North

Slope crude from $107 per barrel to $67 is a 37 percent

decline in average price, but because net value falls more

sharply when price falls, that 37 percent decline in oil

price produces a 63 percent decline in total revenues.

Comparing $107 per barrel oil with $67 per barrel,

Mayer said under the current tax system at $107 per bar-

rel government take (state and federal) is 68 percent,

while at $67 oil, government take is 88 percent. Producer

value is $19.20 per barrel at $107 oil and $2.40 per barrel

at $67 oil, he said.

Comparing the state’s tax systems under ACES and

Senate Bill 21, the current system, government take is

roughly the same at $107 oil — 69 percent under ACES

and 68 percent under SB 21.

But, Mayer said, at $67 per barrel, government take

under ACES would have been only 76 percent, while

under SB 21 it is 88 percent.

He said the analysis is based on figures from

Revenue’s spring forecast: starting with an oil price and

identifying the cost of transport, operating and capital

costs, royalty, property tax, production tax and state and

revenue corporate income tax.

On the credits issue, Cook Inlet and North Slope are

very different, Mayer said: Cook Inlet receives approxi-

mately 50 percent of credits for purchase, but generates

only 5 percent of revenue. In Cook Inlet the production

tax is essentially ELF — low, a fixed rate on gas and gen-

erally no tax on most oil production — but with signifi-

cant credits.

Value of creditsLegislators heard the value of credits from two pro-

ducers and one company working on a production proj-

ect.

Pat Foley of Caelus Energy Alaska told the commit-

tees that Caelus, a privately held independent exploration

and production company, was attracted to Alaska by the

SB 21 tax regime. The company acquired Pioneer

Alaska’s producing Oooguruk field on the North Slope

and has expanded that field with development at Nuna,

acquired additional North Slope acreage from the state

and is just closing on acquisition of a 75 percent interest

in NordAq Alaska acreage in Smith Bay (see story on

page 1).

Benjamin Johnson of BlueCrest Energy, a privately

owned company developing the Cosmopolitan field in

Cook Inlet, said projects in Alaska must compete for

investment with opportunities in other areas, and told

legislators that continuation of tax credits could be a

good investment. At Cosmopolitan, he said, BlueCrest’s

projected future tax credits would be some $190 million

through 2019, some 35 percent of total spending at

Cosmopolitan during that time, while state royalties for

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

Tax credits based on spend, taxes on priceLegislative committees hear admin overview on oil tax credits, enalytica analysis, small producers, explorers on value of credits

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see TAX CREDITS page 15

tion.

Fauske said he’s watched and listened

to that debate, and hopes it won’t be

required because of the time it would take

to get a constitutional amendment on a

general election ballot, but said it appears

that it will be required.

Ken Vasser, general counsel for AGDC,

said he wasn’t speaking for the state, but

the constitutional question on taxes is

whether one Legislature can bind subse-

quent Legislatures, and said the state con-

stitution is clear — the ability to tax won’t

be given away.

He said he thinks a constitutional

amendment will be required if part of the

agreement for the project is setting taxes

and having those taxes apply for a number

of years.

McMahon said the first time a vote

could happen would be in the 2016 general

election, and he said as long as other criti-

cal work continues, the project could main-

tain its schedule for first gas. He said, how-

ever, that ExxonMobil shares BP’s view

that the constitution is sufficient as it is. He

said one of the challenges of a public vote

is that it will be a solid answer, and if the

people say no, it’s difficult to think of what

recovery plan you have to provide a

durable and predictable fiscal plan.

Van Tuyl said if a constitutional amend-

ment were offered in the context of a spe-

cific set of facts and a contract agreed to

and passed by the Legislature that might be

an easier thing than a vote in the abstract.

McMahon said he agreed with Van

Tuyl, that if a constitutional amendment

approach is taken it will be critical to have

the contract known and available to people

so they would know what they were sign-

ing on to — so they would see the prize.

Property taxesCommissioner of Revenue Randy

Hoffbeck said the administration was

working on a simplified methodology for

property tax levied on the AKLNG project.

Bills were introduced late in the session, he

said, to get the issue out for discussion.

Hoffbeck said there has been good feed-

back and some proposed changes, and dis-

cussions on the language with both the pro-

ducers and the Municipal Advisory Gas

Project Review Board. He said significant

progress had been made in discussions

with the producers and with the MAG

group, with language being worked. He

said the administration wants a simple

method that’s robust and dependable and is

moving forward with that task.

He also said that within the last month

the administration is working more dili-

gently on payments during construction,

with a meeting in early July on how impact

payments — payments for impact on com-

munities during construction —are done

elsewhere.

Property tax, Hoffbeck said, is a very

large portion of total government take and

the most consistent of tax flows because it

is not price related. Because it is so impor-

tant, it can’t be dealt with any earlier than

the rest of project economics.

Hoffbeck said the state will likely be the

largest recipient of property tax, so it’s not

just a municipal issue, and said that part of

the puzzle, the split between the state and

municipalities, is still ahead. And that part

of the puzzle, he said, does not involve

the producers, just the state and the

municipalities. l

14 PETROLEUM NEWS • WEEK OF JUNE 21, 2015

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continued from page 8

LNG UPDATE

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

Cook Inlet Energy surrenders spare leasesCompany returns 14 un-unitized leases throughout the Cook Inlet basin; independent investors make smaller transactions

By ERIC LIDJIFor Petroleum News

Cook Inlet Energy LLC surrendered 14 leases in May,

according to the most recent report on leasing activity

in the state published by the Alaska Department of Natural

Resources.

The leases are scattered throughout the Cook Inlet

region.

ADL 392219 and ADL 392220 were offshore leases

between the Cook Inlet Energy-operated Redoubt unit and

the Kenai Peninsula coastline near Nikiski. The leases were

scheduled to expire in late April 2023. Neither had been

drilled, although the Pan-American Forelands State Unit

No. 1 well was drilled just outside ADL 392220.

ADL 392221 and ADL 392222 were to the west of the

Redoubt unit and south of the Tiger Eye unit. Both wells

were set to expire in late May 2023. Neither had been

drilled.

ADL 392228, ADL 392229, ADL 392230, ADL 392231

and ADL 392232 were on the west side of Cook Inlet, west

of the Trading Bay unit. They were set to expire in late April

2023, except for ADL 392232, which would have expired

in late May 2023. ADL 392229 was the location of the

Cherryville Corp. Middle River State unit No. 2 well.

ADL 392237, ADL 392238 and ADL 392239 were just

to the north. The leases were set to expire in late May 2023.

ADL 392238 was the location of Shell’s Middle River State

No. 1 well. ADL 392239 was the location of ARCO’s

Middle River State Unit No. 1.

ADL 392233 and ADL 392234 are along the Kenai

Peninsula coastline south of Point Possession. The leases

were set to expire in late May 2023. Neither had been

drilled.

Toward the end of 2014, Cook Inlet Energy parent com-

pany Miller Energy Resources Ltd. decided to pursue low-

risk activities at its existing developments for the time

being.

Other activitiesKasper Profit Sharing and the Kasper Family

Partnership have separately requested the transfer of vari-

ous small royalty interests (all in values less than 1 percent)

at three leases at the Redoubt unit — ADL 381201, ADL

381003 and ADL 381003 — to the Kasper Family Trust.

The Wheeler Retained Annuity Trust has similarly request-

ed the transfer of small royalty interests (both in values less

than 1 percent) in two leases at the Redoubt unit — ADL

378114 and ADL 374002 — to Wheeler Enterprises LLC.

Sally Selby Nesbit has requested the transfer of a royalty

interest (less than 1 percent) in a lease at the Beluga River

unit — ADL 17658 — to the Nesbit Family Trust.

Stellar Oil and Gas LLC has requested the transfer of

small royalty interests (less than 1 percent) in lease ADL

391094 to seven individual and corporate investors.

Clyde T Boyer Jr. has requested the transfer of various

royalty interests (all in values less than 1 percent) in four

leases associated with the North Fork unit and one lease at

the nearby Nikolaevsk unit to Clyde T Boyer Jr. and Vivian

C. Finlay.

Peter Michael Foley and Melissa McCarty Foley have

requested the transfer of a 0.05 percent royalty interest in

six Kitchen Lights unit leases to Shawn Bartholomae, who

in turn requested a transfer of the same interest in the same

leases to Dr. David Bailey.

Also in May, the state assigned a Beaufort Sea lease to

Hilcorp Alaska LLC. l

—A copyrighted oil and gas lease map from MapmakersAlaska was a research tool used in preparing this story.

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oil and gas produced from Cosmopolitan

would be more than $600 million at a $65

per barrel average oil price.

John Barnes of Hilcorp Alaska said the

company’s goal is to get Alaska costs

competitive with what it costs Hilcorp in

the Lower 48. The company has achieved

that in Cook Inlet, he said, and its goal is

to do that on the North Slope. Hilcorp

began operations in Cook Inlet in 2012

and in 2014 became operator at the

Endicott, Milne Point and Northstar fields

on the North Slope.

Hilcorp’s investment in Cook Inlet

since it acquired fields there has been

more than a billion dollars, Barnes said,

some $330 million a year invested —

compared to some $80 million a year

invested by the previous operators.

He said the state has to decide if it

wants a tax structure that works against

investment. l

continued from page 13

TAX CREDITS

GOVERNMENTWalsh named state pipeline coordinator

Jason Walsh has been named to head the State Pipeline

Coordinator’s Office in the Alaska Department of Natural

Resources.

The office is responsible for developing and maintaining

large-diameter oil and gas pipeline right-of-way leases and

lease compliance efforts for multiple pipelines, including the

trans-Alaska oil pipeline.

Walsh is a lifelong Alaskan with a breadth of natural

resources management experience. After attending graduate

studies in natural resource planning at the University of

Vermont, Walsh held a variety of positions during a decade-

long tenure at DNR, including land planning and development for the Division of

Mining, Land and Water and facilitating right-of-way lease coordination for the

Point Thomson export pipeline and the Alaska Stand Alone Gas Pipeline.

As a member of the state’s Point Thomson permit team, Walsh received a

Governor’s Denali Peak Performance Award in 2013 and was soon after promoted

to operations manager of the SPCO.

Most recently Walsh has served as acting deputy pipeline coordinator and led

SPCO through relocation to the new Geologic Materials Center and initial plan-

ning and permitting activities for the proposed AK LNG project.

“I am honored to lead this team of knowledgeable and hard-working individu-

als and remain committed to DNR’s mission of ensuring that the use of Alaska’s

natural resources is consistent with the public interest,” Walsh said in a statement.

—PETROLEUM NEWS

JASON WALSH

purchasing land, having crews out

drilling bore holes and testing water

wells, doing surveys, holding communi-

ty meetings, people are not dropping the

cynicism and pessimism, but there are

cracks in the cynicism and pessimism,

and people are starting to see the possi-

bility that this is really good work.

Petroleum News: So as you look athow things are now, what gives you opti-mism and what gives you pause aboutthe prospects of Alaska LNG?

Persily: the market gives me pause.

I’m glad that Conoco, BP, Exxon and

TransCanada are looking at using their

own money and not mine because I get

nervous. The commodity markets —

whether it’s cotton, sugar, oil and gas,

iron ore — make everybody nervous,

particularly the energy markets the last

couple of years.

Aside from that I guess what gives

me encouragement is that I see a serious

effort made by the companies bringing

in key people, bringing in people with

expertise on projects from around the

globe, and not just bringing them in for a

couple of days but setting them up as

permanent members of the Alaska LNG

team, and committing substantial

resources.

Yes it is a methodical approach. Yes it

is a careful, measured approach, and I

know many people would like to speed

it up and the problem is when you speed

it up, you make mistakes and you started

spending too much money.

The other thing is if you look at reser-

voir management in Prudhoe Bay which

is where most of the gas will come from.

If you look at reservoir management in

the 2020s and beyond, good reservoir

management dictates that it’s time to

start taking off some of that gas so you

are not going to appreciably damage oil

recovery.

You’ve used the gas for decades by

that point to push the oil over in the

reservoir for collection. Now you can

start finally in the 2020s to pull off some

of that gas — not all of it — and start

diverting some of it into the line. Begin

making money off gas continue making

money off of oil. As the cliché goes: the

time has come.

I guess I see a serious effort, but back

to what gives me pause is the market

which no one can control. At some

point, the companies will reach that

decision where they have to check the

market and make their corporate invest-

ment decision.

Petroleum News: Down here inJuneau, there has been some back andforth between the governor and leadingmembers of the House and Senate. Somesay that’s to be expected with a new gov-ernor, but at some point it also has toease up. Where does this need to end?

Persily: Yes, the governor and signifi-

cant number of legislators are at odds as

to how to proceed with the state-spon-

sored, state-supported backup gas line

project. A significant number of legisla-

tors and the governor are at odds with

the Alaska LNG partnership. The gover-

nor has talked about wanting more own-

ership and more control. The governor

has had a more contentious relationship

with the industry in the past in his role

as attorney for Valdez on oil pipeline

property tax assessments. At some point,

if it’s not going to jeopardize the project,

the governor and the legislators need to

agree a little bit more. They are never

going to agree completely whether it’s

gas line, budgeting, ferry system man-

agement.

They need to agree more on how to

proceed: How much ownership stake

should the state have? What is the role

of the Alaska Gasline Development

Corp. backup project? How much money

should be put into it? How actively

should they pursue it so it doesn’t get in

the way or conflict with the producers

on the bigger project?

I guess there is never going to be 100

percent agreement, but a little less dis-

agreement would be good for the proj-

ect. The governor has an opening for the

Alaska Gasline Development Corp.

board. One of his nominees was rejected

by the Legislature.

Filling that opening would be an

opportunity for the governor to extend

the proverbial extension of the olive

branch if he could find a nominee that

would be acceptable to him and the

Legislature. That would signal: “hey, I’m

willing to work together. I’m not going

to nominate somebody who you are

going to reject. I’m going to put some-

one up you will support.”

As I’m looking for opportunities to

get along, that open seat on the Alaska

Gasline Development Corp. would be an

opportunity to mends those shaky

fences.

Petroleum News: We’ve been underSB 138 for about a year now. What kindof changes are you seeing the last year?

Persily: One thing Alaskans are going

to do differently is we’ve been trained

over the decades to follow the daily

price of oil. It determines the capital

budget, it determines state spending, it

determines the fate of elections and how

much money we have to pass around.

But the daily price of LNG really

doesn’t mean squat in this. The industry

has historically built these megaprojects

on long-term contracts. Long-term con-

tracts are eroding a little bit this year as

there is an oversupply. But looking

ahead to the 2020s demand, nobody is

going to build a $40 billion project on

speculation like they do a duplex or a

zero lot line in South Anchorage.

You are still going to have to have

long-term contracts because that’s how

you get financing. Yes, long-term con-

tracts are down now. But the question

see PERSILY Q&A page 17

continued from page 3

PERSILY Q&A

16 PETROLEUM NEWS • WEEK OF JUNE 21, 2015

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Oil Patch BitsWelsh receives professional land surveyor license

F. Robert Bell and Assoc. is pleased to announce that BrendanWelsh has earned his Alaska professional land surveying license. Welshhas successfully passed the Principles and Practice of Surveying exam,which covers specific topics in surveying such as standards, legal prin-ciples, and professional practices, business practices and types of sur-veys.

This is Welsh’s second certification in less than a year. In October oflast year, he earned his Certified Federal Surveyor certification. Welsh isa civil engineer and land surveyor at Bell and Associates and has hadmore than seven years’ experience with roads, schools, and other edu-cational facilities; and residential, commercial and public works devel-opment projects.

His surveying experience includes conducting topographic and boundary surveys as well asconstruction staking. He is currently leading the North Slope surveying effort in the AK LNGproject. Using his knowledge of surveying practices and procedures, he regularly performsoffice data processing and analysis in preparation of as-builts, plot plans, topographic maps,and design surveys for clients. Welsh is knowledgeable in using various surveying equipmentsuch as total station and other data collectors. He has a bachelor of science in civil engineeringand forest engineering from Oregon State University.

Global establishes Southern California locationGlobal Diving & Salvage Inc. is pleased to announce the expansion of its California region-

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AAECOM Environment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .17

aeSolutions

Air Liquide

Alaska Clean Seas (ACS)

Alaska Communications

Alaska Dreams

Alaska Marine Lines

Alaska Metrology & Calibration Services

Alaska Railroad

Alaska Rubber

Alaska Steel Co.

Alaska Textiles

Alaska West Express

Alpha Seismic Compressors

American Marine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .17

Arctic Controls

Arctic Slope Telephone Assoc. Co-op.

Arctic Wire Rope & Supply

ARCTOS

Armstrong

ASRC Energy Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3

AT&T

Avalon Development

B-FBP

Bald Mountain Air Service

Battelle Anchorage

Bombay Deluxe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5

Brooks Range Supply

Calista Corp.

Canrig Drilling Technology

Carlile Transportation Services

Chevrolet of South Anchorage

CHI Aviation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8

ClearSpan Fabric Structures

CN Rail

Colville Inc.

Computing Alternatives

CONAM Construction

ConocoPhillips Alaska

Construction Machinery Industrial

Cook Inlet Energy

Crowley Solutions

Cruz Construction

Delta Leasing

Denali Industrial

DET-TRONICS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .13

Dowland-Bach Corp.

Doyon Anvil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4

Doyon Drilling

Doyon, Limited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .14

Doyon Universal Services

Egli Air Haul

exp Energy Services

F. Robert Bell and Associates

Fairweather

Five Star Oilfield Services

Flowline Alaska

Fluor

Foss Maritime

Fugro

G-MGBR Oilfield Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5

GCI Industrial Telecom

GCR Tires & Service

Global Diving & Salvage

Global Geophysical Services . . . . . . . . . . . . . . . . . . . . . . . .20

GMW Fire Protection

Golder Associates

Greer Tank & Welding

Guess & Rudd, PC

Harley Marine Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2

Hawk Consultants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .14

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Kenworth Alaska

Kuukpik Arctic Services

Last Frontier Air Ventures

Learn to Return

Lister Industries

Lounsbury & Associates

Lynden Air Cargo

Lynden Air Freight

Lynden Inc.

Lynden International

Lynden Logistics

Lynden Transport

MagTec Alaska

Mapmakers of Alaska

MAPPA Testlab

Maritime Helicopters

Miller Energy

Motion Industries

N-PNabors Alaska Drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7

Nalco

NANA WorleyParsons

NASCO Industries Inc.

Nature Conservancy, The

NEI Fluid Technology

NMS Lodging

Nordic Calista

North Slope Telecom . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .20

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Northern Electric Inc.

Opti Staffing Group

Pacific Alaska Lumber

Pacific Pile

PacWest Drilling Supply

Paramount Supply Company

Parker Drilling

PENCO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .17

Petroleum Equipment & Services

Polyguard Products

PND Engineers Inc.

PRA (Petrotechnical Resources of Alaska)

ProComm Alaska

Price Gregory International

Resource Development Council

Ravn Alaska (formerly Era Alaska)

Q-ZSAExploration

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Sophie Station Suites

STEELFAB

Stoel Rives

Taiga Ventures

Tanks-A-Lot

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Total Safety U.S. Inc.

TOTE-Totem Ocean Trailer Express . . . . . . . . . . . . . . . . . . . . .4

Totem Equipment & Supply . . . . . . . . . . . . . . . . . . . . . . . . .15

TTT Environmental

UIC Design Plan Build

UIC Oil and Gas Support Services

Unique Machine

Univar USA

Usibelli

Verizon

Vigor Alaska

Volant Products

Weston Solutions, Inc.

BRENDAN WELSH

isn’t where they are today. The question

is where are they going to be in 2024

and where does the market think it’s

going to be for signing long-term con-

tracts.

Last year was great if you were sell-

ing LNG on the spot market, getting

$20 per million Btu. This year, not so

good. You’re getting $7 to $8 for the

same molecules, but as we know from

oil prices they go up and they go down.

Long term over a 30-year to 40-year

project life for Alaska LNG, where are

they going to be is what matters. Not

today’s low or today’s high

Petroleum News: You had noted theimportance of a 30-year project life inone of your reports looking at the per-mit application with the EnergyDepartment. Why is that important?

Persily: The expectation at this point

is it will run more than 30 years. The

ConocoPhillips plant at Nikiski opened

up in 1969. That’s been running for 46

years without any significant problems.

Generally long-term LNG sales and

purchase contracts have been running

15 to 20 years.

Of late there are more spot and

short-term sales because buyers are say-

ing boy I can get cheaper prices in the

spot market, let me sign some contracts

in the short-term market and see where

this falls out. I’m not aware of any 30-

year contracts. The difference between

the initial contracts signed and the use-

ful life of the equipment can be great.

If this gets built between gas in

Prudhoe, gas in Point Thomson, gas that

hasn’t even been found yet because

nobody has even explored for gas, this

thing could last for 40 to 50 years.

The 30 years was a factor in the

export permit that Alaska LNG asked

for. The Department of Energy gave a

conditional approval. The longer you

can get for export, it means the longer

you can go without having to go back

for approval again. It’s more value to

you if you can get 30 years rather than

20 years. You’ve got an extra 10 years

before you go back and ask for permis-

sion again. That was a plus for the proj-

ect.

Petroleum News: It seems like thefederal agencies are realizing the scopeof the project — possibly hitting $65billion — is anything remotely close tothis emerging from around the world?

Persily: There is a project called

Gorgon in Australia which is supposed

to come online next year. It’s about $54

billion. A lot of the $54 billion is the

gas field development cost which you

don’t have at Prudhoe and a very

expensive CO2 sequestration where

they are going to re-inject the CO2 deep

underground. In Alaska, they are

already doing re-injecting of water,

CO2. So there are components of

Gorgon that you don’t have here. That’s

the most expensive.

Then there is Yamal LNG in the

Russian Arctic. It’s $27 billion, but

that’s a little misleading because the

Russian government is paying for the

port and airport and other infrastructure

so the Russian developers don’t have to

foot the bill.

Keep in mind Alaska LNG is 2012

dollars so it will be the most expensive.

The Lower 48 projects being built or

proposed are all greenfield. They

already have storage tanks and jetties

because they are being built on the site

of an underutilized import terminal.

Petroleum News: Say, I know I’veasked you this before, but where is thecompetition coming from at least versusthe AKLNG project?

Persily: The competition is world-

wide in that it’s Gulf of Mexico proj-

ects; it’s British Columbia West Coast

projects; it’s African nations; it’s expan-

sions of LNG capacity. Because LNG is

in a ship, unlike a pipeline, it can really

go anywhere. It’s going to come down

to what is the demand and what supply

is out there. You can end up with swaps

where U.S. gas produced in the Gulf

Coast goes to Europe instead of Asia,

but maybe some Mideast gas that would

have gone to Europe doesn’t go there

and instead goes to Asia. Once those

tankers are on the ocean, they can go

anywhere, it’s just a matter of figuring

out shipping costs and where it makes

the most sense to send that cargo. So in

that sense, everybody is our competitor,

not one particular location or one par-

ticular project. It’s who can get into the

market at a price that attracts buyers

and on a schedule that attracts buyers.

Petroleum News: Once on awhile wehear how we’ve missed the window.How do you feel about that?

Persily: I met an interesting guy at a

conference in Singapore in February

who said he has never been a great

believer in windows. His response was

a lot of people get hurt trying to jump

through the window while it’s still

open. Every year there are multiple util-

ities around the world who are signing

contracts for future deliveries. There is

not a window today that won’t come

back. The sooner you can get into the

market, the sooner you can start earning

a return on your investment. Surely you

would like to get into the market when

people are willing to sign higher value

contracts.

Petroleum News: There are a lot ofsteps toward reaching FID (final invest-ment decision). Is there any step morecrucial than the next?

Persily: As far as what Alaskans will

see, to stay on schedule and get to front

end engineering and design (FEED)

next summer. That’s a billion-dollar-

plus commitment to stay on schedule.

The next one would be for the compa-

nies to submit their final environmental

reports and complete their application

to FERC which is tentatively scheduled

for late summer 2016. If they make

those decisions to spend the money on

FEED, go to FERC with full reports

and a clean application that would be a

serious indication that there is progress.

Petroleum News: So with that inmind, what would you like to seeaccomplished by year’s end?

Persily: Certainly, it would be good

to see progress on fiscal negotiations

between the state and its partners, the

producers. That would involve taxes

and fiscal stability to the developers and

the state so you can count on the rev-

enue. It would be good to see progress

on commercial and fiscal negotiations

this year so everybody would feel more

comfortable making that big FEED

decision next year.

Petroleum News: Can the state be apartner and a regulator at the sametime?

Persily: The Legislature passed it and

the public seems to support it so it’s

something that Alaska is going to have

to learn how to manage. There will be

moments when you scratch your head

and say, what am I going to do? Can

they manage it? Will it be difficult at

times? Yes. Is it insurmountable? No.

But it’s a unique situation that I cannot

find anywhere else in the country where

the state takes an equity role in a proj-

ect like this. Hey, this is Alaska. We

love being unique. We love being dif-

ferent. l

PETROLEUM NEWS • WEEK OF JUNE 21, 2015 17

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PERSILY Q&A

cent working interest in NordAq Energy

Inc.’s Tulimaniq leases in Smith Bay,

some 150 miles west of Prudhoe Bay.

The area is “well documented for its

extensive hydrocarbon potential,” the

company said. Slightly more than

117,000 acres (gross) and 26 leases were

assigned to Caelus Energy Alaska Smith

Bay LLC, a wholly owned subsidiary of

Caelus, the company said.

Caelus, as operator, will lead the

exploration program this winter.

Foley, testifying at a committee hear-

ing on the state’s tax credits, told legisla-

tors that without the state’s oil tax credits

the company would not be planning to

drill wells at Tulimaniq.

Caelus has recently sanctioned its

onshore Nuna oil development at the

North Slope Oooguruk field which it

operates and acquired 323,000 North

Slope acres in the state’s fall lease sales.

Defining Smith Bay “The NordAq team has done a great

job of defining the geologic potential at

Smith Bay,” Caelus President and CEO

James Musselman said in the company’s

release. “Our team is ready to take the

helm and get to work on exploring and

appraising the Tulimaniq play. What we

see in this region has us all pretty moti-

vated.”

Musselman said Caelus’ winter explo-

ration planning is under way, and said the

company looks forward to continuing its

strong working relationships with North

Slope communities, the North Slope

Borough and state and federal regulators

to ensure a smooth transition.

“We’re also extremely fortunate to be

supported in our efforts by North Slope

veterans Doyon Drilling and Cruz

Construction. The winter exploration

operation will require upwards of 400

personnel to drill 1-2

exploration/appraisal wells — it’s a large-

scale program,” Musselman said.

He also said the state’s oil fiscal sys-

tem, including exploration credits, is what

attracted Caelus to Alaska in 2013 and

said it has been a “key component in the

company’s recent business decisions.”

NordAq commentsNordAq Energy Chief Executive

Officer Paul Devine said his company is

encouraged by Caelus’ commitment to

Alaska and the experience Caelus brings

to the project.

“NordAq is very grateful to have a

partner of their caliber to operate on our

behalf, and commit the energy and capital

to a significant play like Tulimaniq.”

“We are also very grateful to CIRI

Energy, NordAq’s secured lender, for the

role it played in facilitating this important

transaction,” Devine said.

Where is Tulimaniq?Smith Bay is roughly 150 miles from

Kuparuk River unit Drill Site 2P and

some 70 miles from Barrow. NordAq had

proposed drilling from a single ice island

in some 1 to 4 feet of water near the

mouth of the Ikpikpuk River, with a 64-

man drilling camp and a 19-man camp at

the staging pad, either Oliktok Point or

DS-2P Pad. NordAq proposed two access

routes, with route selection to depend on

weather and sea ice conditions at the time

of project startup in December 2014. The

priority route was along Harrison Bay and

the Kogru River, maximizing the use of

sea and lake ice and allowing smoother

travel; the staging for this route would

have been just offshore from Oliktok

Point.

The alternate route would have begun

from a staging area at DS-2P or an adja-

cent ice pad, cross the Colville River at

Ocean Point and proceed along the histor-

ical travel route before heading north to

the Tulimaniq drill site.

—KRISTEN NELSON

“Obviously, it means we can be compet-

itive globally. This is great news for British

Columbia,” he said.

The partners are Petronas 62 percent,

China’s Sinopec 15 percent, Indian Oil

Corp. 10 percent, JAPEX 10 percent and

PetroleumBrunei 3 percent.

Coleman said that British Columbia’s

vast gas resource, most of it stuck in the

ground with nowhere to go, is “basically

sold.”

He expressed confidence that the consor-

tium’s remaining loose ends can be tied

together, creating thousands of construc-

tion, service and gas development jobs,

potentially giving Canada’s energy industry

its greatest lift since the Alberta oil sands

started on their growth path in the 1980s.

Pacific NorthWest could also provide

Western Canadian gas producers with a

market outlet to offset a crippling loss of

export sales in the United States.

Coleman expects the British Columbia

Legislature will reconvene in July to sign

off on the project.

Federal approval neededIn addition, the proponents need regula-

tory approval from the Canadian govern-

ment covering environmental issues,

notably measures to mitigate threats to a

salmon spawning area — a decision that

may not be made until after a federal elec-

tion expected in October.

As well, there are delicate negotiations

involving the provincial government and

the consortium to conduct with the Lax

Kw’alaams First Nation which rejected an

offer of C$1.14 billion in benefits over 40

years to protect a salmon habitat adjacent to

Lelu Island.

“We will work with them to solve their

issues,” Coleman pledged. “There is some

additional design work and some research

being done to accommodate those concerns

... you will see that the Lax Kw’alaams will

come together with other First Nations that

have already endorsed the project.”

He said that dealing with the loose ends

could see construction start in the final quar-

ter, with the first LNG shipments occurring

in 2019, opening the way for a total invest-

ment in the project of C$36 billion.

Canada’s Natural Resources Minister

Greg Rickford said LNG has the “potential

to diversify our energy markets and product

offering, creating jobs and economic

growth for Canadians.”

John Winter, chief executive officer of

the British Columbia Chamber of

Commerce, said the Pacific NorthWest

breakthrough is a “truly historic announce-

ment ... once-in-a-generation stuff. It is rare

that we witness a brand new industry com-

ing to British Columbia.”

AltaGas next in lineNext in line is a group led by Calgary-

based AltaGas, whose Chief Executive

Officer David Cornhill said the Douglas

Channel project at Kitimat may even beat

Pacific NorthWest to market if it makes a

final investment decision this year.

The much smaller venture, with plans

for first-phase shipments of 550,000 metric

tons a year — compared with Pacific

NorthWest’s initial goal of 12 million met-

ric tons — could start deliveries by late

2018.

“There is nothing we see at this point

that will stop us,” he said. “There are some

tight deadlines, so it’s not a walk in the park,

but clearly we think it’s achievable.”

The other leading edge contender is the

LNG Canada project, led by Shell Canada,

with Korea Gas, Mitsubishi and PetroChina

as stakeholders, which is working towards a

final investment decision in 2016, targeting

eventual shipments of 24 million metric

tons a year.

Bruce Ralston, natural gas spokesman

for British Columbia’s opposition New

Democratic Party, said his party is hopeful

there will be a final signing off by Petronas,

but pointed an accusatory finger at Premier

Christy Clark for making such sweeping

promises in the 2013 election, including the

use of LNG revenues to build a C$100 bil-

lion Prosperity Fund.

“There are no shovels in the ground

yet,” he said, while insisting that First

Nations must be involved as “true part-

ners” in the industry. l

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ENERGY LIFT LNG naysayers air doubtsAgainst a renewed chorus of hope that British Columbia will enter the global

LNG trade, there is no shortage of doubters who say export projects will not be

viable at current natural gas prices.

The International Energy Agency, in a five-year outlook for the gas market,

said “prospects for (Canadian) LNG projects have deteriorated and no plant is

expected to be operational (before 2020).”

“One of the key — and largely unexpected — developments of 2014 was weak

Asian demand,” IEA Executive Director Maria van der Hoeven said.

“Indeed, the belief that Asia will take whatever quantity of gas at whatever

price is no longer a given. The experience of the past two years has opened the

gas industry’s eyes to a harsh reality: in a world of very cheap coal and falling cost

for renewables, it was difficult for gas to compete.”

The IEA said “new LNG projects will struggle to get off the ground at current

prices” — a claim that critics of the British Columbia government use to explain

why Premier Christy Clark has been so willing to meet industry demands for

lower taxes and greater incentives.

Natural Gas Development Minister Rich Coleman said his government is well

aware that it is operating in a competitive environment.

“We are aware of the short-term challenges outlined in the (IEA) report and

have plans to address them,” he said, without offering further details.

Jennifer Winter, of the University of Calgary’s School of Public Policy, said

British Columbia’s LNG hopes are “definitely a lot worse” than they were a few

years ago because of the glut of international supply.

“Australia started building facilities 10 years ago and now they are coming on-

line. As well there are existing facilities that have ended their 20-year contracts

and have spare capacity to sell on the spot market,” she said.

Currently, seven LNG projects have received final investment decisions in

Australia, which is poised to become the world’s largest exporter by 2018.

In addition, Africa is expanding its production, although the lack of a regula-

tory regime is likely to slow development in Tanzania and Mozambique, while

Russia, supported by huge reserves, has signed two large export deals with China

that could supply 17 percent of that country’s needs.

Andrew Weaver, the only Green Party member of the British Columbia

Legislature, said the government should not be promoting LNG in the face of a

shrinking global market.

“I would describe that as irresponsible, desperate and reckless,” he said.”It’s

reckless economic policy to continue down this path, chasing a falling market.”

—GARY PARK

continued from page 1

CAELUS TRACTS

As part of the deal, AIDEA intends to

sell the Pentex subsidiaries Titan Alaska

LNG LLC and Arctic Energy

Transportation LLC to the Hilcorp sub-

sidiary Harvest Alaska LLC for $15.5

million. The sale is expected to close

sometime in the third quarter.

“We expect the Pentex acquisition to

be a short-term strategic investment that

can play a significant role in helping

achieve long-term success for the Interior

Energy Project,” AIDEA Executive

Director John Springsteen said in a state-

ment. “This acquisition will promote an

integrated gas distribution system that can

be built and operated in a more efficient

manner for the benefit of Interior Alaska

residents and businesses.”

AIDEA made a point of describing the

acquisition as a “temporary” measure that

will better integrate existing efforts to

expand the gas distribution grid through-

out the Interior.

With its access to cheaper capital

unavailable to private companies, AIDEA

believes it can reduce costs for existing

Fairbanks Natural Gas customers by

some 13.3 percent this coming winter.

AIDEA believes a consolidated distribu-

tion system could eventually save as

much as $1.8 million annually in opera-

tional efficiencies. “The ultimate goal of

this transition will be a single, locally

controlled utility serving the Interior,”

Springsteen said.

AIDEA expects to complete this tran-

sition within two years and earn approxi-

mately $2.91 million in the process. That

would translate to a 5.06 percent rate of

return.

The deal will cut the existing Pentex

operation in half.

Currently, through its various sub-

sidiaries, Pentex liquefies Cook Inlet nat-

ural gas at a facility in Point MacKenzie

and trucks it to Fairbanks for storage and

distribution.

If all the components of the deal close

as expected, Harvest Alaska will take

over the liquefaction and trucking opera-

tions through its acquisition of Titan and

Arctic Energy Transportation, leaving

AIDEA to focus on storage and distribu-

tion in Fairbanks.

As a public utility, Fairbanks Natural

Gas will no longer be subject to regula-

tion by the Regulatory Commission of

Alaska. Instead, AIDEA will adopt rate-

setting procedures.

This further zigzags the twisted history

of the Interior natural gas market.

After a contracting hiccup in Cook

Inlet nearly cut off supplies to Fairbanks

in late 2006, regulators required

Fairbanks Natural Gas to find an alterna-

tive source of natural gas.

The utility negotiated a gas supply

agreement with a North Slope operator in

2008. But to make use of the contract, the

utility needed to build an expensive lique-

faction plant.

Fairbanks Natural Gas sought public

assistance to fund the project. Instead, the

Parnell administration launched the

Interior Energy Project. The public-pri-

vate partnership would use grants, bonds

and loans to finance an LNG trucking

operation from the North Slope.

As the lead agency in the project,

AIDEA ultimately selected the interna-

tional infrastructure firm MWH America

Inc. to be its private sector partner for the

Interior Energy Project. In doing so, it

passed over bids by Pentex and by

Spectrum Alaska LLC.

At the same time Pentex was facing

competition for the upstream portion of

its project, Fairbanks Natural Gas also

faced competition for the downstream

portion of the project.

Fairbanks Natural Gas asked regula-

tors to expand its existing service area in

the city of Fairbanks to include much of

the Fairbanks North Star Borough.

Expecting to soon become a large monop-

oly, the utility voluntarily accepted rate

regulation. The Regulatory Commission

of Alaska had previously exempted the

company from rate regulation to help it

better compete against the unregulated

fuel oil companies so dominant in

Fairbanks.

Annoyed with the slow pace of

Fairbanks Natural Gas expansion in the

region, the three municipalities in the

Fairbanks North Star Borough jointly

formed a competing utility, called the

Interior Gas Utility. They asked regula-

tors for a competing service area. The

debate between the two utilities was

unusually heated and at times veered into

ugliness.

The RCA ultimately rejected the

Fairbanks Natural Gas application in

favor of the Interior Gas Utility applica-

tion. That left Fairbanks Natural Gas

without a liquefaction plant, without an

opportunity to expand and with an expen-

sive rate case to swallow.

For a time it seemed the Fairbanks

North Star Borough would be served by

two utilities.

Through the grant-making portion of

the Interior Energy Project, AIDEA fund-

ed Interior Energy Project distribution

pipelines and an expansion of Pentex’s

storage capacity.

Toward the end of 2014, Pentex

announced plans to sell its liquefaction

subsidiary to Harvest Alaska. It also

sought regulatory approval for a 10-year

contract with Hilcorp, which would limit

the amount of natural gas Fairbanks

Natural Gas needed from the North Slope.

In early 2015, the deal between

AIDEA and MWH fell through. The

problem was largely about cost. MWH

questioned whether it could hit the pric-

ing target AIDEA desired.

AIDEA saw the acquisition of Pentex

as a way to braid the various frayed

threads of the Interior Energy Project by

making it easier to create an integrated

grid in the Interior.

—ERIC LIDJI

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The program outline is the most detailed development

proposal yet from Linc and is significantly larger than

ideas the company presented seven months ago. In an

annual report from late October 2014, after both wells

were drilled, the company anticipated “that the initial

development of Umiat could include the drilling of up to

70 wells.”

The current program also offers a more detailed devel-

opment timeline. The company expects permitting and

engineering to continue through 2019 and procurement,

fabrication and installation to continue through 2023. The

company would begin drilling the Lower Grandstand for-

mation in early 2022 and the Upper Grandstand in early

2023.

Those dates are far more specific than previous fore-

casting from the company.

In August 2012, before it began drilling, Linc

announced an “aggressive timeline” to bring Umiat into

production in five to seven years, with peak production of

50,000 barrels per day. By October 2013, after completing

only one of a proposed four-to-five-well program, Linc

said it planned “to aggressively develop this field once

commerciality is determined” but no longer offered a spe-

cific timetable for bringing the field online.

A production forecast shows the field coming online in

2023, peaking at 50,000 barrels per day by 2026 and

declining gradually to approximately 5,000 bpd by 2047.

Although discovered nearly 70 years ago, the Umiat oil

field has remained undeveloped because of its remote

location and complex geology. Linc believes it has solved

the latter challenge by combining horizontal drilling with

a well-tinkered completion strategy.

The former challenge remains formidable, especially at

current oil prices.

The previous exploration campaigns required Linc to

build a 102-mile snow road connecting Umiat to the

Dalton Highway. A development would require a gravel

road or a complex transportation scheme to carry equip-

ment and supplies to the existing Umiat airstrip. And a

successful development would need to support a 100-mile

pipeline.

The State of Alaska spent years studying a proposed

“Road to Umiat,” only to set the project aside amid criti-

cism from nearby villages, skepticism from lawmakers

and a budget shortfall that made grand infrastructure proj-

ects unfeasible for foreseeable future.

Although it surely would have welcomed a publicly

funded road, Linc always maintained it could make Umiat

economic even if it had to finance the road itself.

Engineering work over the past two years initially

identified 12 potential routes for connecting the field to

existing infrastructure. Of those, six were believed to be

viable based on allowable road grades and attempts to

avoid environmentally sensitive areas.

The company is currently comparing three alternatives

(see map).

The Toolik East route would branch in a northwesterly

direction from the Dalton Highway north of Pump Station

4 and the Toolik Research Station. The Franklin Bluffs

route would head south-southwest from the Franklin

Bluffs staging area north of Pump Station 2. The

Meltwater route would use existing roads through the

Prudhoe Bay and Kuparuk River units and continue south

and then southwest along a newly built road. l

continued from page 1

UMIAT PLAN

continued from page 1

AIDEA BUY

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it needs for its drilling program but is still

waiting for a letter of authorization from

the U.S. Fish and Wildlife Service for the

unintended disturbance of some marine

mammals during drilling operations, and

the company has yet to obtain approved

permits to drill in the Chukchi, Baldino

said.

In May the Bureau of Ocean Energy

Management approved Shell’s Chukchi

Sea exploration plan.

Burger prospectShell has previously said that it hopes

to move its fleet into the Chukchi Sea in

early July. The company wants to operate

its two drilling vessels concurrently,

drilling exploration wells in the Burger

prospect, about 70 miles northwest of the

Chukchi coastal village of Wainwright.

“We remain committed to operating in

a safe, environmentally responsible man-

ner and look forward to exploring our

Chukchi leases in the weeks to come,”

Baldino said.

In 2012 Shell drilled the top hole sec-

tion of the Burger A well before having to

suspend the drilling operation because the

company’s oil containment system was

not ready for use. The company had

planned to re-enter and complete that well

when its drilling program restarted.

However, in May of this year Ann

Pickard, Shell’s executive vice president

for the Arctic, told the Houston Chronicle

that the company now plans to drill two

new wells in 2015, targeting the south-

western and southeastern edges of the

Burger prospect. The Burger A well was

closer to the center of the prospect,

Pickard said. Pickard told the Chronicle

that the decision to drill the two new

wells was based on the results of recent

seismic data processing and that Shell had

determined that the new wells were more

likely to prove out an oil find than the

Burger A well.

Strategic playWith the Chukchi Sea having the

attributes of a world-class petroleum

basin, Shell sees its Arctic venture as a

long-term strategic play to establish a

future source of major oil resources. The

company says that, despite the challenges

of operating in such a remote region, the

drilling in relatively shallow water will be

straightforward and safe, with multiple

oil spill prevention procedures and tech-

nologies in place. The company has

assembled a major set of assets for

responding to any oil spill emergency,

including the containment dome, a well

capping stack, oil spill response vessels

and a tanker for collecting any spilled oil.

But environmental organizations and

their supporters remain adamantly

opposed to Shell’s plans, saying that

Arctic offshore oil exploration and devel-

opment pose unacceptably high risks to

the fragile Arctic environment.

Environmental activist organization

Greenpeace said that its vessel Esperanza

had launched an inflatable boat carrying

an activist from the indigenous communi-

ty ahead of the Polar Pioneer as the

drilling unit left Seattle, while two

Greenpeace swimmers had accompanied

the small protest boat. Earlier, a fleet of

kayakers had assembled in the Seattle

port, in protest at Shell’s plans.

On May 8 District Court Judge Sharon

Gleason ordered a preliminary injunction

imposing a number of restrictions on

Greenpeace, including banning people

associated with the organization from

interfering with or boarding 29 specified

vessels. Gleason also imposed exclusion

zones around the vessels. Greenpeace has

since appealed the preliminary injunction

to the Court of Appeals for the 9th

Circuit. In a June 12 order rejecting a

Greenpeace motion to dismiss Shell’s

request for the injunction, Gleason com-

mented on the Greenpeace boarding of

the Polar Pioneer in early April while the

drilling rig was being transported across

the Pacific Ocean. Gleason said that this

action was “sufficiently akin to piracy” to

justify court jurisdiction on the high seas,

outside U.S. territorial waters.

Contingency plan upheldIn a crucial court decision, on June 11

a majority of a three-judge panel in the

Court of Appeals for the 9th Circuit

rejected an appeal against the approval

by the Bureau of Safety and

Environmental Enforcement of Shell’s

Chukchi Sea oil spill prevention and

response plan. Had the court upheld the

appeal, Shell would presumably have had

to place its Chukchi Sea drilling plans on

hold.

A group of 10 environmental organi-

zations had originally launched the

appeal in federal District Court in Alaska

in 2012, claiming that Shell’s plan over-

estimated the quantity of oil that could be

recovered following an oil spill; that the

plan did not adequately consider the

impact of sea ice in trapping oil; and that

Shell had not described its Arctic oil con-

tainment system. The appeal also claimed

that BSEE should have conducted an

environmental analysis under the terms

of the National Environmental Policy Act

in conjunction with its review of the plan.

After the District Court dismissed the

appeal in August 2013, the plaintiffs ele-

vated the appeal to the 9th Circuit.

In rejecting the appeal, the panel of

9th Circuit judges said that the plaintiffs

had misinterpreted language in the con-

tingency plan regarding oil recovery

rates, and that BSEE had not acted arbi-

trarily in approving the plan. The panel

majority said that, because Shell’s plan

met statutory requirements, BSEE had to

approve it. And, given the non-discre-

tionary nature of this approval, the

agency did not have to call for a consul-

tation under the Endangered Species Act,

nor was a review under the National

Environmental Policy Act required.

Judge Dorothy Nelson dissented from

the majority decision, saying that BSEE

had discretion to approve or disapprove

Shell’s plan and, thus, should have initi-

ated an Endangered Species Act consul-

tation and an environmental review.

Meantime, a group of environmental

organizations is continuing an appeal

against the legality of the 2008 Chukchi

Sea lease sale in which Shell purchased

its leases. On June 17 federal District

Court Judge Ralph Beistline approved a

new schedule for the case, with all briefs

required by Oct. 9. l

continued from page 1

DRILLING FLEET EPA authorizes Shell drilling dischargesThe Environmental Protection Agency has authorized waste discharges from

Shell’s drilling operations in the Chukchi Sea this summer. The authorization

comes under the terms of a National Pollutant Discharge Elimination System gen-

eral permit for Chukchi Sea exploration and applies to operations by the drilling

vessels Noble Discoverer and Polar Pioneer at four locations on the Burger

prospect, about 70 miles northwest of the Chukchi coastal village of Wainwright.

The discharges authorized include water-based drilling fluids and drill cut-

tings; domestic waste; and bilge water.

The four drilling sites referenced in the authorization consist of the Burger F,

Burger J, Burger S and Burger V wells, in water depths ranging from 145 to 148

feet. Shell has said that it anticipates drilling two wells this year, in the southwest-

ern and southeastern edges of the Burger prospect. That would appear to point to

the J and the V wells, based on a well location map submitted by Shell to EPA.

—ALAN BAILEY

NOAA issues IHA for Shell overflightsThe National Oceanic and Atmospheric Administration Fisheries Service has

issued an incidental harassment authorization, allowing the unintended, minor

disturbance of marine mammals by overflights of the Beaufort and Chukchi seas

that Shell plans to conduct this year in conjunction with its Chukchi Sea drilling

program. According to a Federal Register notice for the issuance of the authoriza-

tion, Shell wants to use overflights to conduct surveys of the sea-ice break up at

the beginning of the open water season and of the freeze up at the end of the sea-

son. The company plans to use fixed wing aircraft and helicopters, with the timing

of the surveys depending on ice and weather conditions, the notice says.

The Fisheries Service requires measures designed to mitigate disturbance

caused by the overflights, including a requirement for a protected species observer

to participate in each flight; the maintenance of a one-mile radius from areas with

high seal concentrations; and engagement with local communities to avoid distur-

bance to subsistence activities.

—ALAN BAILEY