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

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

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

page3

Q&A: Rodell says long-term view,financial planning needed for LNG

Vol. 19, No. 47 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of November 23, 2014 • $2.50

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

November Mining News inside

NANA REGIONAL CORPORATION

The Red Dog Mine is celebrating the25th anniversary of production. NANARegion Corp. President and CEO MarieGreene reflected recently on the tra-vails and triumphs that led to one ofthe strongest and most successfulindigenous people-mining companypartnerships in the world. Page 4.

A special supplement to Petroleum NewsWEEK OF

November 23, 2014

3 BC talks river treaty with Alaska Mines minister prefers stronger state-provincial bonds to federal involvement

10 Copper North re-designs Carmacks New mine plan for Yukon project due by year's end, 2017 production target

13 AMA: 75 years of miner advocacy Miners association reflects on achievements, prepares for upcoming challenges

Big acre salesState gets bids on 524,387 North Slope acres, 107,189 acres in Beaufort

By KRISTEN NELSONPetroleum News

Nov. 19 saw four oil and gas lease sales in

Anchorage — three state and one federal —

with companies submitting bids on 708,346 acres.

The state’s North Slope areawide sale drew the most

interest, attracting 297 bids on 254 tracts, 524,387

acres, making it the fourth largest since areawide

sales began in 1999. Of recent sales the state’s 2000

areawide North Slope sale drew the most interest,

with 657,520 acres leased.

The Beaufort Sea areawide, drawing 57 bids on 42

tracts, 107,189 acres, is also fourth in interest among

recent sales, with the 2011 Beaufort Sea areawide

drawing the most interest with 242,796 acres leased.

The federal Bureau of Land Management drew

bids on seven tracts, 66,650 acres, while the state’s

Foothills areawide only drew bids on only two tracts,

10,120 acres.

Dollar volumes were impressive, $54.5 million

for the state’s North Slope areawide, $5 million for

the Beaufort Sea sale, $59.7 for the three state sales

combined.

These are good numbers compared to areawide

sales in recent years, but small compared to the $900

million the state took in at its 1969 North Slope sale

(412,548 acres) and the $567.3 million in took in at

its 1979 Beaufort Sea sale (296,308 acres).

AIDEA selling jack-upMinority partners buying after failing to secure long-term charter in Cook Inlet

By ERIC LIDJIFor Petroleum News

The Alaska Industrial Development and Export

Authority is selling the Endeavour drilling rig

after failing to secure a long-term charter in Cook

Inlet for the jack-up rig.

The public corporation is selling its stake in the

rig to its two partners, the Singapore-based Ezion

Holdings Ltd. and the Ezion-subsidiary Teras

Investments Pte. Ltd.

Technically, the rig is owned by the joint ven-

ture Kenai Offshore Ventures LLC. AIDEA is the

preferred owner of the joint venture. Ezion and

Teras are the common owners.

The operating agreement gave the common

owners an option to buy out AIDEA.

Even though Kenai Offshore Ventures was

unable to find a long-term customer, AIDEA said

“there continues to be great interest in having the

Endeavour available for Cook Inlet drilling.”

Without a contract, Kenai Offshore Ventures

sought other opportunities. If the sale goes

through, the rig would leave the Cook Inlet basin,

Mission difficult more soEnbridge’s Northern Gateway leader retiring after 3 years of battling odds

By GARY PARKFor Petroleum News

Janet Holder, after three years of riding the

stormy seas at the helm of Enbridge’s Northern

Gateway project, has decided to end her 20 years

at Enbridge on Dec. 31 and retire to “focus on my

family and my personal health.”

The unspoken message is that she is tired of

defending the indefensible and dealing with the

personal abuse that has been thrown her way.

And a lot of those insults have come from

Prince George in north-central British Columbia

where she now plans to spend “more time with my

husband at our family home.”

It’s still possible that Northern Gateway might

find a way over seemingly insurmountable hurdles

and proceed.

But the more immediate question being posed is

whether Holder is leaving to clear the decks for

Enbridge to scrap Northern Gateway, a planned

C$7.9 billion twin-pipeline system to export

525,000 barrels per day of crude bitumen to Asia

and possibly the United States and import 193,000

bpd of condensate.

Holder’s decision comes only a few weeks after

see LEASE SALE page 8

Without a contract, Kenai OffshoreVentures sought other opportunities. If thesale goes through, the rig would leave theCook Inlet basin, bound for South Africa.

see JACK-UP SALE page 15

But the more immediate question beingposed is whether Holder is leaving to clearthe decks for Enbridge to scrap Northern

Gateway ...

see GATEWAY LEADER page 16

State approves Placer expansionAfter a lengthy and complicated appeals process, the state

is reversing an earlier decision and allowing ASRC

Exploration LLC to expand the Placer unit on the North Slope.

The ruling requires the exploration arm of Arctic Slope

Regional Corp. to file a new plan of exploration by the end of

the year, post a $2.5 million performance bond by mid-

January 2015 and meet a series of work commitments culmi-

nating in an exploration well by May 2016. The Placer unit

would keep its original expiration date of Sept. 8, 2016.

The Nov. 13 decision helps resolve a three-year dispute

between the company and the Alaska Department of Natural

Resources over the best way to explore the Placer unit.

Linc still mulling Umiat saleLinc Energy Ltd. is still considering offers to sell the Umiat

oil field.

The Australian independent “continues to engage with

these parties while pursuing its permitting and development

plans for the field,” according to recent quarterly filings.

In September, the company launched “a formal process to

work with additional parties who have expressed an interest in

the potential acquisition of the company’s entire USA based

oil and gas portfolio,” which would include the undeveloped

Umiat oil field.

While the earlier announcement provided little insight

about the nature of the inquiry, the current update suggests

that the solicitation came in response to the results of Umiat

exploration work this past winter. “The company’s Umiat 23H

horizontal well has attracted attention, with Linc Energy

receiving expressions of interest from third parties regarding

see PLACER EXPANSION page 14

see UMIAT SALE page 15

2 PETROLEUM NEWS • WEEK OF NOVEMBER 23, 2014

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

6 AP declares for Walker; Parnell concedes

10 PrairieSky widens horizon

Encana spinoff picks up Range Royalty, adding 3.5 million acres; no government royalties because of 19th century land grants

10 Ready for some heavy lifting

Cenovus Energy, Devon Energy ready to move aheadon projects at Telephone Lake, Pike; BlackPearl ready to resume Onion Lake work

3 Rodell: Long-term view needed for LNG

Revenue commissioner: state can’t afford not to bepartner; says oil tax change, $3 billion to pension funds, are steps in process

7 EPA emissions rule comes under scrutiny

Utilities say one size fits all approach to regulating power plant CO2 emissions may not work in Alaska’s unique situation

GOVERNMENT

INTERNATIONAL

FACILITIES

5 SAExploration planning big spend

Houston-based seismic company intends to use a $150 million senior secured note to purchase equipment for Alaska operations

FINANCE & ECONOMY

State approves Placer expansion

Linc still mulling Umiat sale

Big acre sales

State gets bids on 524,387 North Slope acres, 107,189 acres in Beaufort

AIDEA selling jack-up

Minority partners buying after failing to secure long-term charter in Cook Inlet

Mission difficult more so

Enbridge’s Northern Gateway leader retiring after 3 years of battling odds

ON THE COVER

ENVIRONMENT & SAFETY

EXPLORATION & PRODUCTION

6 NOAA publishes AK oil spill risk report

Agency considered risks associated with shipping, oil development and other activities in 14 regionoffshore the Alaska coastline

4 Imperial puts dent in crown

Suspends production at Kearl oil sands project,compounding series of planning, delivery, operational kinks that inflated price tag

11 ConocoPhillips asking for target practice

11 State files opposition to US water rule

11 Third oil delivery from Arctic offshore

11 BP using robotics for EOR rock tests

15 Sharp decline in polar bear population

Alaska’sOil and GasConsultants

GeoscienceEngineeringProject ManagementSeismic and Well Data

3601 C Street, Suite 1424Anchorage, AK 99503

(907) 272-1232(907) 272-1344

www.petroak.cominfo@petroak.com

SIDEBAR, Page 4: Oil sands selling job

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

What's the big attraction?

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To advertise in Petroleum News callSusan Crane at 907-770-5592, orBonnie Yonker at 425-483-9705. Tosubscribe visit PetroleumNews.com,call 907-522-9469, or email circulation@PetroleumNews.com.

By STEVE QUINNFor Petroleum News

R evenue Commissioner Angela Rodell says one

financial decision for the state may have a

stronger link to another than what may first appear. But

these choices, she says often can stand on their own to

address certain market forces like declining oil prices.

Rodell sat down with Petroleum News and spoke of

the steps the Legislature and executive branch took

toward addressing resource development and the finan-

cial implications drawn from them and other pieces of

legislation not so obviously con-

nected.

Petroleum News: Let’s startwith low oil prices. Nobody likeslow oil prices, not the state, notthe industry. Consumers might likeit. Still, what kind of reality checkdoes $80 and below oil bring tothe state?

Rodell: That’s a good question.

We’ve been focused on produc-

tion, as you know, the last couple of years. I think it

reminds us that it’s a combination of production and

price. We’ve always taken and lived with the volatility

that is the commodity of oil. The other reality check it

provides is that it makes us ask how dependent do we

want to be on oil from an economic standpoint in this

state going forward. We can talk about additional

exploration, we can talk about additional production, all

of those things, but at the end of the day are there other

industries, are there other areas that we should be

focused on developing, whether it’s mining or doing

things for our fisheries or for forests, all of the other

natural resources that we have.

Petroleum News: Do you think the $80 oil caughtpeople off guard because for so long we’ve been enjoy-ing $100-plus a barrel prices?

Rodell: I think it has. I think there was a sense — I

saw it nationally and you saw it in a lot of forecasting

done worldwide — that there was a new natural floor at

$100 and the fact that we broke through that so easily I

think that did catch so many people by surprise. I think

what’s important to remember from our standpoint is

we base the budget on an average for the entire year so

when we see volatility day in day out like we are see-

ing here, it doesn’t necessarily mean that our price fore-

cast might be as off as some might think it could be.

So for example we were at $105 in the spring and

people see it at $80 and think we are $25 off. We are

maybe for today and tomorrow, but when you finish off

the averages for the year, we’ll be in a different place

so I think it’s important to recognize we forecast an

average for the entire year not on a day-to-day basis.

Petroleum News: How does the current tax regimestack up against the previous one at $80 a barrel?

Rodell: I think it’s important to

remember that under any tax regime, we

are collecting less revenue, first of all.

Prices are down and that’s just the nature

of the tax regime. Having said that, the

tax regime under the More Alaska

Production Act is collecting more rev-

enue as a result because we have a higher threshold at

lower prices so we are collecting more than we would

under the old tax regime in the current price environ-

ment.

Petroleum News: So is the current tax regime stillhelping the state’s bond rating?

Rodell: It definitely is. There have been public press

releases coming out of Moody’s. What it’s done is it’s

created a floor and so there is a minimum tax and a

higher base tax than there was under the old regime so

it does provide more support from a credit perspective.

It creates a bottom band and a higher threshold of rev-

enue, which gives great comfort to creditors.

Petroleum News: Even as you’re not the Departmentof Natural Resources, do you still track new develop-ments like the S-2 pad at Kuparuk?

Rodell: We do and we continue to get information

from both industry and DNR and that helps inform our

production forecasts. I think this one is a great signal.

We’ve seen a public commitment from all of the major

producers to continue to invest in Alaska and continue

to develop infrastructure and continue to produce as

much oil as they can from the North Slope.

Petroleum News: Even though it does not contributeto the state’s coffers, why is oil from federal landsimportant to the state?

Rodell: I think federal oil is important, especially if

you are talking about OCS (the outer continental shelf),

for example. It puts resource into TAPS. It maintains

that infrastructure, lowers the cost of transportation for

all oil and thereby generates additional revenue to the

state. While we don’t get production tax or royalty per

se off some of that, the benefits it adds to keeping

TAPS going is very important to the state as well as

maintaining the infrastructure in the state.

Petroleum News: The state’s D.C. delegation hasbeen working on getting a higher revenue share. Doyou have a role in that, even if it’s just discussion withfolks in Washington?

Rodell: We do. I think it’s important that as that

resource gets developed, that Alaska have a say and a

share in the resource similar to our brethren in the Gulf

of Mexico. We are interested in doing

what we can to assist our D.C. delegation

any way we can. I think we will see what

happens with the makeup of the Senate

changing. I think part of the difficulty was

that development of the OCS always felt

far out in the future. I think as it gets clos-

er and closer to coming online, it’s going to become

more of a priority to the state to advocate for Alaska’s

share.

Petroleum News: You talk about getting closer tothings in a timeline, do you think that now the debateover oil taxes has subsided, it will be easier for thestate to move forward. Does it make your job easier?

Rodell: I do. I think the tax debate has made it chal-

lenging, for sure, as to getting additional areas opened

up or finding additional prospects because the econom-

ics are more certain for companies now in a way they

were not in previous years. No question that it makes

my job easier. However it had turned out, it makes it

easier. Having certainty around a tax code is imperative

for economic investment of any kind.

So when you are constantly upending tax codes for

businesses, it creates a business climate that’s not con-

ducive to investment. I’m getting feedback that there is

more certainty now, there is more predictability. There

is more confidence. We are seeing more longer term

contracts. The supply chains are going farther out than

in the past. One of the interesting things about SB 21 is

we don’t have a full tax year yet.

The first full tax year doesn’t end until Dec. 31. It

takes a while for things to cycle into business activity.

We are seeing things ramp up. You could argue all the

uncertainty around the referendum in August may have

delayed certain decision making just until they knew

for sure what things were going to look like.

Petroleum News: Let’s shift to the gas pipeline.There’s still a lot to learn about whether it’s going to beeconomical. Do you think the state can afford to be apartner in a project this vast?

Rodell: I think the state can’t afford not to be a part-

ner. And so what we need to do as a state, recognizing

l G O V E R N M E N T

Rodell: Long-term view needed for LNGRevenue commissioner: state can’t afford not to be partner; says oil tax change, $3 billion to pension funds, are steps in process

PETROLEUM NEWS • WEEK OF NOVEMBER 23, 2014 3

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see RODELL Q&A page 13

By GARY PARKFor Petroleum News

Imperial Oil has become Canada’s

largest integrated oil company by fol-

lowing the lead of its ExxonMobil parent

and acting only when it is certain all of

the bases have been covered and refusing

to run with the herd.

That has seen Imperial puzzle many

industry observers by taking a measured,

plodding approach to exploiting its

resource wealth in the oil sands, Arctic

and LNG sector.

But it’s not as if Imperial (now 70 per-

cent owned by ExxonMobil) lacks a track

record to defend its style.

The company was launched 134 years

ago when 16 refiners in Ontario joined

forces, launching a company that has gen-

erally functioned like a well-oiled

machine, keeping itself out of the public

limelight as much as possible.

All of which causes furrowed brows

when its performance in bringing north-

ern Alberta’s Kearl oil sands project into

production is weighed against a problem-

plagued history that has stretched over a

decade.

If the troubles had been limited to a

couple of budget overruns that pushed the

final bill from about C$8.9 billion to

C$12.9 billion it would merely have

placed Imperial among the ranks of other

oil sands developers where, in fact, over-

runs of 50 percent and more were once

common.

Equipment malfunctionThe latest setback for Kearl has been a

head shaker for Imperial, which

announced on Nov. 10 that it was shutting

down operations for an unspecified num-

ber of weeks to tackle an equipment mal-

function by replacing parts to correct

unexplained vibrations in an ore crusher.

The company has offered no estimates

of costs or anticipated lost production.

The reversal came right on the heels of

the third-quarter results which credited

Kearl with making a major contribution

to a 45 percent year-over-year jump in

profits to C$936 million.

Output from the operation averaged

92,000 barrels per day — a solid show-

ing, but still short of the targeted 110,000

bpd, reflecting Imperial’s continuing

struggles to overcome bugs in the system

more than a year after Kearl was brought

on-stream.

Chief Executive Officer Rich Kruger

said in April that the challenges have

included manufacturing and installation-

related defects on some of more than

8,000 valves that regulate fluid flow and

hydraulics.

Early cost overrunsJust getting to the startup point was

plagued by cost overruns and delays relat-

ed to processing modules that were at the

center of Kearl’s highest-profile problem.

Original plans to ship the units along

United States highways to Alberta

encountered a public backlash, and court

rulings in Montana and Idaho, forcing

Imperial to reduce the modules to even

smaller components, which Kruger said

“certainly didn’t help” achieve the

planned production ramp up.

“It’s like taking a high performance

sports car, cutting it in half, and then

moving it a few miles down the road and

trying to reassemble it,” he told reporters

in New York last April.

Kruger said the defects should not sig-

nal long-term concerns over Kearl, taking

the pragmatic view that “if something

doesn’t work you’ve got to replace it or

repair it.”

Doubling capacityImperial is also holding out hope that

its second phase, which will double

capacity, should start producing in 2015

and pull operating costs below the $30 a

barrel in the initial phase, although that

performance is sharply above the $20 a

barrel some analysts had expected in the

near-term.

There has been little talk lately around

Imperial’s original goal of a three-phase

development to achieve 330,000 bpd,

which was raised to 345,000 bpd by 2020.

However, the company website still

lists the 345,000 bpd goal, which it hopes

will be possible through future debottle-

necking and presumably “learnings” from

the first-stage experience.

(Kearl is owned 79 percent by

Imperial and 29 percent by ExxonMobil,

a partnership that has access to an esti-

mated resource of 4.6 billion barrels,

enough to support an operating life of 40

years.)

In contrast, oil sands powerhouse

Suncor Energy is targeting operating

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

Imperial puts dent in crownSuspends production at Kearl oil sands project, compounding series of planning, delivery, operational kinks that inflated price tag

4 PETROLEUM NEWS • WEEK OF NOVEMBER 23, 2014

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owned by Petroleum Newspapersof Alaska LLC. The newspaper ispublished weekly. Several of theindividuals listed above work forindependent companies that con-

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Oil sands selling job The Canadian oil sands industry is immersed in what could be a battle for its

right to grow.

Political leaders such as Jim Prentice, Alberta’s newly elected premier, are put-

ting the sector on notice that changes to environmental legislation are on the way,

effectively telling the industry to get its house in order.

That might explain a blizzard of “public service” spots on TV to counter what is

derided as the dirtiest source of crude by showing how much the industry con-

tributes to jobs and how much it cares about the planet.

The industry’s message got another lift earlier in November when the Canadian

Energy Research Institute updated a four-year-old study showing how much the oil

sands could contribute to Canada’s economic well-being.

CERI President Peter Howard said that by separating the oil sands from mining

and other heavy industries the positive impact on provinces other than Alberta has

doubled since the original study was released in early 2011.

If the industry grows as planned over the next 25 years, CERI has concluded that

Alberta’s gross domestic product will reap C$3.43 trillion, leaving another C$440

billion for the rest of Canada.

And that includes a lowering of long-term oil prices to US$85 a barrel from

US$100 in the 2011 forecast, translating into tax revenues of C$302 billion and

see SELLING OIL SANDS page 5

see IMPERIAL MOVES page 5

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6300 Petersburg St., Anchorage, AK

costs for its $13.5 billion Fort Hills mine

to land in the range of $20-$24 a barrel,

with sustaining capital projected at $3 a

barrel, compared with Kearl’s mainte-

nance costs of $5-$10 a barrel, which the

company has partly blamed on stricter

tailings pond regulations imposed by

Alberta’s energy regulator.

Output being testedKruger said in April that about 22

refineries were testing Kearl’s output,

including a handful of shipments to a

refinery in Malaysia through Kinder

Morgan’s Trans Mountain pipeline to the

Pacific Coast.

He said that crude had been “well-

received” in the market, noting that the

refineries had experienced no operational

hitches.

However, Kruger had delivered a

veiled hint in spring 2013 that not all was

going smoothly with Kearl when he

urged reporters to keep in mind the

“absolute scale” of the project, noting that

adjustments were being made as the com-

ponents were assembled.

“Nothing that it would describe as

unusual or atypical,” he said, in what still

amounted to a rare confession by

Imperial that it was dealing with blips.

“It’s just a big world-class project.”

Those comments were made less than

two months after Kruger occupied the

company’s top job, causing some analysts

such as Michael Dunn of FirstEnergy

Capital to wonder whether the change

was related to cost overruns at Kearl.

Reconfiguring in 2010Roll the clock back to late 2010 when

Imperial announced that after two and a

half years of construction it was reconfig-

uring the project to minimize facility

requirements and potentially reduce the

plant’s footprint.

The rumblings of discontent caused

Kruger’s predecessor Bruce March to fire

back in March 2012 at those pointing fin-

gers at Kearl’s rising costs, saying time

would tell who had the best project.

“I can’t comment on what any other

competitor is looking at and I wish they

wouldn’t comment about what we’re

doing,” he said in a rare flash of peevish-

ness from Imperial.

“We’ll see where the other competitors

come out. I’m just as anxious as you

maybe to see where they go.”

March was provoked by Suncor’s for-

mer Chief Executive Officer Rick

George, who put himself in the unusual

role of critic when he said some of the

numbers at Kearl “look extremely high.

They look really way out of range.”

“Our current estimates are significant-

ly below those they’ve announced,”

George said, referring to the newly estab-

lished partnership with France’s Total to

build two new mines with combined out-

put of 260,000 bpd and a plant to upgrade

300,000 bpd of crude bitumen.

Who was right and who was wrong is

unlikely to ever be resolved now that one

of the Suncor/Total mines has been can-

celled and the other remains under a

cloud, while the upgrader is on hold

indefinitely. l

continued from page 4

IMPERIAL MOVES

C$600 billion in royalties for Alberta,

with royalties soaring from C$4.4 bil-

lion in 2013 to C$18.2 billion in 2023.

The Canadian government is predict-

ed to collect C$574 billion in related

taxes over the 25 years.

CERI estimates total investment in

new projects, plus sustaining capital

spending on existing projects, will be

about C$514 billion in the 2014-2038

period.

The study said indirect and induced

jobs in the oil sands will grow from

514,000 in 2014 to 802,000 in 2028,

with Alberta experiencing an increase

from 146,000 to 256,000.

Greg Stringham, vice president of oil

sands for the Canadian Association of

Petroleum Producers, told the Calgary

Herald that the study’s key point

demonstrates “how the benefits of

developing this resource are actually

being spread out” across Canada.

“It’s impacting places that normally

wouldn’t be aware of the benefits that

are coming through jobs, through busi-

nesses sending their products to us and

through government revenues,” he said.

The research organization projects

that oil sands production will grow from

1.98 million bpd in 2013 to 3.7 million

bpd in 2020 and 5.2 million bpd in 2030

and assumes that TransCanada’s Energy

East and Keystone XL pipelines,

Enbridge’s Northern Gateway and

Kinder Morgan’s Trans Mountain

expansion will all go ahead.

—GARY PARK

continued from page 4

SELLING OIL SANDS

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

SAExplorationplanning big spendHouston-based seismic company intends to use a $150 millionsenior secured note to purchase equipment for Alaska operations

By ERIC LIDJIFor Petroleum News

The seismic firm SAExploration

Holdings Inc. plans to spend $20 mil-

lion on equipment for its Alaska operations

during the fourth quarter, the company said

in recent filings.

In June 2014, the Houston-based com-

pany announced plans to sell up to $150

million in senior secured notes to repay cer-

tain debts, fund Alaska purchases and pay

other costs.

Even with falling oil prices, “Overall we

remain assured in our ability to maintain

our strong position within our core markets

as we begin turn our attention towards

2015,” President and CEO Brian Beatty

said during a quarterly earnings call with

analysts. “Our current expectations for next

year are in large part based on increased

exploration activities in Alaska which we

believe will be our strongest near-term

growth market.”

Through the third quarter, the company

had signed contracts for nearly $27 million

in equipment for its Alaska operations, of

which nearly $10 million went on the

books for the third quarter. Those expenses

contributed to a nearly $23 million net loss

for the company during the quarter. But

increased revenues tempered the losses,

year over year.

SAExploration reported revenues of

nearly $120 million through the first nine

months of the year from its North

American operations, a 39.4 percent

increase over the same period last year,

driven largely by increased seismic activi-

ties across the North Slope.

South American Exploration began con-

ducting seismic operations in Peru in 2006.

In 2011, after expanding across South

America and into Pacific markets including

Australia, the company acquired Datum

Exploration in Calgary and Northern

Exploration Services in Alaska and estab-

lished North American operations as

SAExploration.

By the end of 2013, SAExploration

Alaska was already a familiar face in Cook

Inlet and the Interior, contracting projects

for Linc Energy Ltd., Hilcorp Alaska LLC

and Doyon Ltd. and permitting a program

over the waters of the upper Cook Inlet.

(The program overlapped with a program

being permitted by Furie Operating Alaska

LLC.)

Currently, SAExploration Inc. is pro-

posing a 3-D seismic program for the Cook

Inlet Outer Continental Shelf. The compa-

ny had originally proposed the survey for

this coming winter but deferred the pro-

gram to the latter half of 2015 due to per-

mitting delays. The 697.9 square mile sur-

vey would hug the southern Kenai

Peninsula.

In November 2012, SAExploration and

the Native corporation Kuukpik Corp.

formed Kuukpik SAE LLC, a joint venture

for North Slope seismic programs. The

joint venture will last for five years.

SAExploration owns a 49 percent interest

in the joint venture.

In the latter half of 2013, the joint ven-

ture proposed the Colville Delta 3-D

Seismic Survey over portions of the

Oooguruk, Nikaitchuq and Kuparuk River

units and the Umingmak 3-D Seismic

Program around Nuiqsut. Both were three-

year programs.

The company typically sub-contracts

for its seismic surveys in Alaska and

Canada.

SAExploration credits its expansion in

Alaska to Executive Chairman Jeff

Hastings, who founded Fairweather

Geophysical and continued managing

Alaska operations when Veritas DGC

acquired Fairweather and when

CGGVeritas acquired Veritas DGC. l

“Our current expectations for nextyear are in large part based on

increased exploration activities inAlaska which we believe will beour strongest near-term growth

market.” —SAExploration Holdings

Inc. President and CEO Brian Beatty

By ALAN BAILEYPetroleum News

Since the 1989 Exxon Valdez disaster

fouled the pristine environment of

Alaska’s Prince William Sound, the pos-

sibility of another offshore oil spill

calamity has become a subject of some-

times heated debate, as well as being a

major factor in the slowing of new moves

to explore in the seas around the Alaska

coast. But what are the odds of future oil

spills happening? And what risk might

these spills pose to Alaska’s ocean envi-

ronment?

In an attempt to put some objectivity

around answers to these questions and

hence provide some strategic guidance to

those involved in planning for future oil

spill responses, the National Oceanic and

Atmospheric Administration, or NOAA,

has carried out a comprehensive analysis

of oil spill risks in the Alaska offshore

and has now published a report on the

results of that study.

Defining oil spill risk as a combination

of the probability of a spill happening and

the scale of the negative consequences of

the accident, NOAA considered spills that

might result from a number of operations,

ranging from marine shipping to offshore

oil exploration.

“Alaska’s waters are rich in biological

resources that are sensitive to spilled oil,”

the report says in its introductory para-

graph. “These waters are also host to oil

exploration/production activities and

heavy vessel traffic, and are bordered by

land-based facilities that transfer, store

and handle oil.”

14 regional zonesThe risk model presented in the report

considers the Alaska offshore as 14 broad

geographic zones, ranging from the

Chukchi Sea and the Beaufort Sea in the

north to the Aleutians in the south. Zones

in southern Alaska include the Cook Inlet

and Prince William Sound regions.

Within each of the zones the model

encompasses six two-month seasonal

periods spanning an entire year, while

considering four general oil types that

may be spilled: crude oil, heavy oil, light

oils and distillates.

Within each geographic zone and sea-

sonal period, and for each oil type, the

analysis considers the scales of possible

oil spills in terms of both the maximum

most probable discharge and a worst case

discharge. The “maximum most probable

discharge” is a term used by the U.S.

Coast Guard, for example, to specify a

maximum volume of oil likely to be

spilled as a result of some specific type of

accident. A “worst case discharge” is the

most oil likely to be spilled as a result of

an accident, assuming efforts to halt the

spill fail.

The analysts used oil spill data from

1995 to 2012 to assess the probabilities of

different types of spills in different geo-

graphic zones for different times of the

year. Then, using a literature review of

future spillage risk, the analysts assessed

what the probabilities would be in 2025,

taking into account factors such as antici-

pated changes in offshore activity and

changing risk mitigation technologies.

To model the environmental vulnera-

bilities of different geographic zones, the

analysis assigned vulnerability scores to

major natural habitat types and to a vari-

ety of wildlife species.

Areas of greatest riskIn terms of the potential impacts of

maximum most probable discharges on

the environment, the study found that, on

average across the year, southeast Alaska,

the Aleutian region and the

Kodiak/Shelikof Strait region are current-

ly at greatest risk, a result that presum-

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Better.

GOVERNMENTAP declares for Walker; Parnell concedes

As votes continued to be counted in

Alaska’s gubernatorial contest, the

Associated Press declared challenger

Bill Walker the winner and Gov. Sean

Parnell conceded the election.

As of Nov. 17, ballots had been

counted for 55.98 percent of 509,011

registered voters. The nonaligned

“unity” ticket of Bill Walker and

Byron Mallott had 48.1 percent of

votes cast for governor, 134,428, to

45.87 percent, 128,203, for Parnell and Anchorage Mayor Dan Sullivan.

The tally in the race for U.S. Senator, with Republican Dan Sullivan the win-

ner, was 135,207, 47.9 percent, for Sullivan and 129,170, 45.83 percent, for

incumbent Democratic Sen. Mark Begich.

In Alaska legislative races, there were no close Senate contests.

In the House, Democrat Matt Claman led Republican Anand Dubey 3,847 to

3,756 in Anchorage district 21, 50.41 percent to 49.22 percent. In Southeast, non-

affiliated Daniel Ortiz led Republican Chere Klein 3,527 to 3,425, 50.57 percent

to 49.11 percent, in district 36.

The Associated Press reported that Alaska voter turnout was the highest it had

been in a midterm general election since 1994, with this year’s 56 percent com-

pared to 64 percent in 1994.

—KRISTEN NELSON

GOV. SEAN PARNELLBILL WALKER

l E N V I R O N M E N T & S A F E T Y

NOAA publishes AKoil spill risk reportAgency considered risks associated with shipping, oil developmentand other activities in 14 regions offshore the Alaska coastline

see SPILL REPORT page 16

By ALAN BAILEYPetroleum News

Following the early June release of the

Environmental Protection Agency’s

proposed new rule for curtailing carbon

dioxide emissions from U.S. power gen-

eration plants, people have been trying to

assess the potential impact of the rule on

how electricity is generated, distributed

and used. In Alaska the RCA, or

Regulatory Commission of Alaska, has

opened a formal docket to gather infor-

mation about how the rule might impact

the state. And on Oct. 16 the commission

held a technical conference, to discuss

with power utilities and others the various

issues and questions that the rule raises.

A general theme that seemed to per-

meate the comments and discussions was

that the circumstances surrounding power

generation in Alaska are unique, thus

making it inappropriate to try to apply a

multi-state, one-size-fits-all approach to

reducing Alaska’s carbon footprint.

Unlike in the Lower 48 states, Alaska

has an isolated power grid, with a small

total electrical load, and a number of very

small, isolated rural power systems. The

grid itself spans several main population

centers, many miles apart and connected

to each other by single transmission lines.

Reductions by 2030The EPA rule sets each state a target to

reduce its power generation emissions by

2030 by a specified percentage of those

emissions, based on emissions data that

the agency has assembled. The emissions

encompassed by the rule come from

large, commercial-scale generation facili-

ties that deliver power for use by con-

sumers. Each state must prepare a plan

for how its reduction target will be met. If

a state does not manage to prepare an

EPA-approved plan within a required

timeframe, EPA will step in and impose

its own plan. And EPA has set interim

state targets that would apply in the peri-

od 2020 to 2029, to reflect the ramp up of

the impact of the state plans.

EPA has suggested four “building

blocks” for emissions reduction: the

improved efficiency of existing power

stations; the replacement of existing fos-

sil-fuel burning power stations by modern

fossil-fuel plants that are less carbon

intensive; the replacement of fossil-fuel-

generated energy by energy that creates

little or no carbon dioxide; and the reduc-

tion in electricity demand through

improved energy efficiency. Comments

on the proposed rule are due by Dec. 1.

Target for AlaskaFor Alaska, the EPA has set an emis-

sions target for 2030 of 1,003 pounds of

carbon dioxide per kilowatt hour generat-

ed. That represents a drop in emissions of

26 percent compared with the 1,352

pounds per kilowatt hour of emissions

that the agency says the state’s major

power stations were generating in 2012.

But the Alaska Railbelt power utilities

have been making major changes to their

power generation arrangements since

2012. At the beginning of 2013 Chugach

Electric Association and Municipal Light

& Power took over operatorship of the

Southcentral Power Project, a new high-

efficiency, combined-cycle, gas-fired

power station that has been replacing

generation capacity from the old, ineffi-

cient Beluga power station on the west

side of Cook Inlet. Municipal Light &

Power is also upgrading its own

Anchorage generation facility, installing

a modern, high-efficiency plant.

Chugach Electric has in the past sold

power generated at Beluga to other utili-

ties, including Homer Electric

Association on the Kenai Peninsula and

Matanuska Electric Association in the

Palmer/Wasilla area of Southcentral

Alaska. But both Homer Electric and

Matanuska Electric are taking over their

own power generation using efficient

modern plants. Some people participating

in the RCA conference commented that

the new Matanuska Electric power plant,

slated to come on line during the first

quarter of 2015, appears to have a capac-

ity below the threshold for the proposed

EPA emissions rule, thus presumably tak-

ing emissions from that plant out of the

emissions inventory to be tallied in 2030.

Also in the context of the size thresh-

old for power plants, RCA chairman

Robert Pickett commented that under the

EPA rule Alaska would not appear to be

credited for reducing the use of oil-fueled

power generation across the state.

Chugach ElectricBradley Evans, chief executive officer

of Chugach Electric, told the commission

that in 2012 Chugach Electric’s carbon

dioxide emissions rate was about 1,200

pounds per kilowatt hour, a figure just

below the EPA’s baseline statewide num-

ber for that year. By 2016 Chugach

Electric anticipates its emissions rate to

drop to 941 pounds per kilowatt hour, an

emissions rate below the EPA target for

2030.

During that 2012 to 2016 period

Chugach Electric will have moved from

an energy mix of 89 percent natural gas,

10 percent hydro and 1 percent wind, to

80 percent natural gas, 16 percent hydro

and 4 percent wind, Evans said.

Evans commented that there needs to

be an understanding of how EPA plans to

measure the results of implementing the

four emission-reducing building blocks

that the agency proposes. For example, it

is unclear how some new significant but

modest-sized hydro and wind power

plants might factor into EPA’s calcula-

tions for the 2030 target, Evans said.

Evans also pointed out that, if a planned

major hydropower plant at Watana on the

Susitna River comes to fruition that “lit-

erally obliterates the emissions rate for

everybody.”

However, renewable energy projects

currently under consideration by

Chugach Electric typically involve ener-

gy costs two to three times those of the

gas-fired power that would be displaced,

the utility said in written comments.

Evans also told the commission that

unification of the dispatch of power on

the Railbelt transmission grid could

reduce emissions by enabling the more

efficient use of power generation facili-

ties. But executives from other utilities

questioned whether unification of the grid

would have a significant emissions

impact.

Homer ElectricHarvey Ambrose, director of power

production and transmission for Homer

Electric, told the commission that his util-

ity’s implementation of new modern gas-

fired power generation could reduce the

utility’s carbon emission to below the

EPA’s target level. But he questioned

whether, in applying its rule, EPA would

give credit for the power generation effi-

ciency improvements that the Alaska util-

ities have been implementing since 2012.

Homer Electric is also considering

three potential hydroelectric projects, a

possible tidal power project and a com-

munity solar power project in the town of

Homer, Ambrose said.

However, in written comments filed

with RCA, Homer Electric, citing some

practical issues such as relatively inflexi-

ble gas supply arrangements, said that it

would have difficulty in integrating more

than 2 megawatts of fluctuation power,

l G O V E R N M E N T

EPA emissions rule comes under scrutinyUtilities say one size fits all approach to regulating power plant CO2 emissions may not work in Alaska’s unique situation

PETROLEUM NEWS • WEEK OF NOVEMBER 23, 2014 7

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Building exploration baseThe bigger news from the sales was the

bidders: Caelus Alaska Exploration, new to

the state as the operator at Oooguruk, taking

over from Pioneer Natural Resources,

appeared to be looking for exploration

acreage. Prior to the sale the company held

40,373 acres of state leases.

Caelus was apparent high bidder on

263,674 acres in the North Slope sale, 50

percent of the acreage receiving bids in that

sale, and apparent high bidder on 59,120

acres in the Beaufort Sea sale, 55 percent of

the acreage receiving bids in that sale, for

combined acreage of 322,795 acres and

more than $15 million in bids.

In the Beaufort Sea sale Caelus topped

the bidding, with more than $2.26 million in

apparent high bids, 45 percent of the sale’s

winning bids, and was second in the North

Slope sale with $12.7 million, 23.4 percent

of that sale’s apparent high bids.

With the exception of a few outliers,

Caelus took tracts in a broad fairly contigu-

ous sweep across the Slope (see map) from

south of Prudhoe Bay, adjacent to existing

Great Bear leases on the west and south, to

south of Point Thomson. In the Beaufort it

was bidding against ConocoPhillips on

some leases; in the North Slope sale its pri-

mary competition was Armstrong affiliate

178 & 48 LLC.

High bids on ‘billion-dollar fairway’ Armstrong affiliate 70 & 148 LLC,

which held some 144,639 acres of state oil

and gas leases prior to the sale, was appar-

ent high bidder on 179,832 acres, with

$38.3 million in apparent high bids across

both the sales, the highest bid total of any

company, and one which accounted for 64

percent of apparent high bids in the North

Slope and Beaufort sales, compared to the

28.5 percent of total acreage on which the

company was apparent high bidder.

While the company picked up acreage

from the Nikaitchuq area in the Beaufort to

large blocks south of Prudhoe — where it

competed with Caelus on a number of leas-

es — and south and east of Meltwater, what

drew the most attention at the sale was its

bids on tracts between Kuparuk and Alpine,

the so-called billion-dollar fairway.

The company’s bids on tracts 1037 and

1040 were $2,537.73 an acre, bids of some

$6.5 million each for the tracts, the highest

per-acre and tract bids in any of the sales.

Bids of $1,757.89 per acre for tracts 1041

and 1044, produced bids for those tracts of

$4.5 million each. A bid of $1,457.37 per

acre for tract 1142 produced a total bid of

$3.73 million, and $1,007.73 per acre for

tract 1139 produced a total bid of $2.58 mil-

lion. There was competitive bidding on a

number of these tracts, but no per-acre bids

in the range of those 70 & 148 put on the

table. The company paid an average of

$212.70 per acre.

Southern acreage; filling inThe third largest bidder in the sales —

participating only in the North Slope sale —

was Burgundy Xploration of Houston,

which added to 8,640 acres it acquired pre-

viously as apparent high bidder on 90,720

acres for which it bid $2.59 million. The

block of 60-plus of the state’s smaller quar-

ter blocks runs west from the Haul road

south of Great Bear acreage.

ConocoPhillips Alaska took 7,396.31

acres in the Beaufort sale, paying $1.36 mil-

lion, $183.59 per acre.

Great Bear Petroleum Ventures II picked

up 5,760 acres, filling a hole in its existing

acreage, paying $211.85 an acre for a total

of some $1.22 million.

Kuparuk River unit owners

ConocoPhillips, BP, Chevron and Exxon

Mobil bid $250 an acre for a single 2,560-

acre tract adjacent to the southern edge of

the unit, $640,000.

Woodstone Resources picked up 8,120

acres near Umiat, paying $32 an acre for a

total of $259,840.

Paul Gavora and Alaska LLC, bidding

50/50, picked up 11,660 acres in the

Beaufort sale, paying $122,196.80, $10.48

an acre.

Hilcorp Alaska, just taking over from BP

as operator of several North Slope fields,

took one tract, 2,533 acres, at $71,481.26, in

the Beaufort sale, northwest of Milne Point,

one of the fields it is now operating.

In the Foothills sale, R3 Exploration

Corp., bid on two tracts, 10,120 acres —

east of Linc’s proposed Umiat development

NPR-AThe federal Bureau of Land

Management National Petroleum Reserve-

Alaska lease sale drew three bidders and a

total of $658,978.20 in bids on seven tracts,

some 66,650 acres.

NordAq Energy took five tracts adjacent

to a block of six tracts it already holds in

central NPR-A, 45 percent of the sale total

at $294,342.20.

ConocoPhillips Alaska, 78 percent, and

Anadarko Petroleum, 22 percent, took one

tract adjacent to the Greater Mooses Tooth

unit, bidding $206,201, 32 percent of the

sale total.

And ConocoPhillips Alaska took one

tract on the southern edge of tracts south of

and adjacent to the Greater Mooses Tooth

unit, which the company is in the process of

developing, paying $158,425, 24 percent of

the lease sale total. l

—A copyrighted oil and gas lease mapfrom Mapmakers Alaska was a researchtool used in preparing this story.

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continued from page 1

LEASE SALE

PETROLEUM NEWS • WEEK OF NOVEMBER 23, 2014 9

National Petroleum

Reserve Alaska

ANWR

1002 Area

Arctic National

Wildlife Refuge

Beaufort Sea

020

40

60

80

10

Miles

Arctic Slope, Alaska: 2014 Oil & Gas Lease Sale Preliminary ResultsCo

pyrig

ht 2

01

4

MA

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AK

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S ALA

SKA

70 & 148, LLC

Burgundy Exploration

Caelus Alaska Exploration

Gavora, P; Alaska LLC

Hilcorp Alaska

R3 Exploration

Woodstone Resources

NordAq Energy, Inc

ConocoPhillips Alaska Inc

Great Bear Petroleum

Ventures II

Apparent High Bidders

Current Lease

US BLM NPRA Sale Tract

State of Alaska Sale Tract

Beaufort Sea

North Slope Foothills

North Slope

Deferred

NSAW High Bid

Tracts 1037 & 1040

$2537.73/acre

FHAW High Bid

Tract 763

$17.76/acre

BSAW High Bid

Tract 1 61.

$199.88/acre

NPRA High Bid

Tracts 2014-H-161

$53.67/acre

By GARY PARKFor Petroleum News

For all of the question marks swirling

around the near-term prospects for

Western Canada’s heavy crude, operators

show no signs of taking a time out.

Cenovus Energy and Devon Energy are

both ready to take advantage of regulatory

approvals for two oil sands projects and

junior producer BlackPearl Resources plans

to resume work on a Saskatchewan heavy

oil venture while expanding a similar proj-

ect in Alberta.

Cenovus said it has obtained approval

from the Alberta Energy Regulator and the

Alberta government to launch what it

describes as a “cornerstone asset” — its

wholly owned Telephone Lake project that

could eventually yield more than 300,000

barrels per day over 40 years.

The thermal recovery operation is

scheduled to come on stream in two phases

of 45,000 bpd each, based on confidence

that more than 300 test wells over the past

10 years have established a reservoir that

has a similar thickness to its existing

Christina Lake operation.

Cenovus also reported success from a

dewatering pilot project that has demon-

strated it can remove a layer of water on top

of the oil sands deposit and replace that with

compressed air which is expected to

improve the steam-to-oil ratio and reduce

the environmental impact.

The company said an independent

reserves evaluator has given Telephone

Lake a best estimate of economic contin-

gent bitumen resources of 2.6 billion bar-

rels, which will be reclassified to proved

plus probable reserves once it decides in

2015 on the timing of development.

Cenovus has two operating oil sands

projects — Foster Creek with 150,000 bpd

of current gross production capacity and

Christina Lake at 138,000 bpd.

A partnership of Devon and BP received

approval from the Alberta government for

the 105,000 bpd Pike thermal project, in

which Devon spent C$500 million in 2010

to acquire a half share and take over opera-

torship.

A Devon spokeswoman said an expect-

ed capital budget and work plan should be

released this quarter.

FirstEnergy Capital analyst Michael

Dunn estimated a greenfield project similar

to Pike would carry a capital cost of

C$45,000 to C$60,000 per flowing barrel,

putting the price tag in the range of C$4.7

billion to C$6.3 billion.

The Pike leases are just south of Devon’s

existing Jackfish operation, where work has

recently finished on the last of three phases

of 35,000 bpd each.

BlackPearl is selling shares and raising

its lending facility, opening the door to

resume work on its Onion Lake project in

Saskatchewan, having decided in June to

halt a planned C$350 million debt issue to

pay for the 12,000 bpd project because of

unstable debt markets for oil sands projects.

It now hopes to raise C$175 million

before the end of 2014 to proceed with an

initial 6,000 bpd phase.

BlackPearl is also seeking a joint ven-

ture partner to develop its planned 80,000

bpd Blackrod oil sands project in Alberta,

starting with a 20,000 bpd first phase at a

cost of up to C$800 million.

In addition, the company said it will

expand its enhanced oil recovery project in

north-central Alberta by taking advantage

of lower royalty rates the Alberta govern-

ment introduced during the summer, which

BlackPearl expects will cut its current roy-

alties of 22 percent to 5 percent for eight to

10 years.

Based on results from a pilot project, its

plans include mixing water and chemicals

and injecting them to initially re-pressur-

ize the reservoir and boost recovery rates

from the oil in place from 3 percent-5

percent to 18 percent. l

10 PETROLEUM NEWS • WEEK OF NOVEMBER 23, 2014

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By GARY PARKFor Petroleum News

P rairieSky Royalty — the Encana spinoff which col-

lects royalties from producers who extract oil and nat-

ural gas on lands where it owns mineral rights — is in full

flight.

Just six months after being created it has struck a C700

million deal to take over Range Royalty, a limited partner-

ship, adding another 3.5 million acres of royalty-free land

to its portfolio, boosting its holdings to more than 9 million

acres.

The acquisition will give PrairieSky a toehold in

Saskatchewan’s Viking light oil play and add production of

about 3,000 barrels of oil equivalent per day to the 15,500

boe per day it pumped in the third quarter.

For the transaction to close it must gain approval from

two-thirds of Range unitholders, about one-third of whom

have already agreed to tender their stakes.

Governments are unable to collect royalties on the type

of land controlled by PrairieSky and Range as a result of

land grants made by the Canadian government in the 19th

century to Canadian Pacific Railway.

No rush for more landFor now PrairieSky indicates it is in no rush to snap up

more land, declaring it is “very happy with the position we

currently have.”

Third-quarter production was 43 percent crude oil, 10

percent natural gas liquids and 47 percent dry natural gas.

Chief Executive Officer Andrew Phillips said three

other third-quarter acquisitions — involving Penn West

Petroleum, Ember Resources and Whitecap Resources —

should benefit PrairieSky because the new leaseholders

will be more active drillers on his company’s properties.

“I expect you’ll see the predominance of activity

focused on what we consider our top four plays,” he said,

referring to the Montney and Duvernay in Western Canada

and the Eagle Ford and Permian in the United States, with

Encana gaining entry to the Permian by acquiring Athlon

Energy for US$7.1 billion.

EncanaEncana raised C$1.67 billion from the initial public

offering of PrairieSky, then collected another C$2.6 billion

by selling its remaining 54 percent of the company.

That will help Encana make a “substantial” increase in

its 2015 capital budget, even if benchmark crude prices

remain around US$80.

Encana said it expects capital spending of up to US$2.6

billion this year and cash flow of up to US$3.3 billion, with

production peaking at 2.9 billion cubic feet of gas equiva-

lent per day (including 89,000 bpd of oil and liquids). l

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

PrairieSky widens horizonEncana spinoff picks up Range Royalty, adding 3.5 million acres; no government royalties because of 19th century land grants

Governments are unable to collect royalties onthe type of land controlled by PrairieSky andRange as a result of land grants made by theCanadian government in the 19th century to

Canadian Pacific Railway.

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

Ready for some heavy liftingCenovus Energy, Devon Energy ready to move ahead on projects at Telephone Lake, Pike; BlackPearl ready to resume Onion Lake work

Cenovus has two operating oilsands projects — Foster Creek

with 150,000 bpd of current grossproduction capacity and Christina

Lake at 138,000 bpd.

BlackPearl is also seeking a jointventure partner to develop its

planned 80,000 bpd Blackrod oilsands project in Alberta, startingwith a 20,000 bpd first phase at a

cost of up to C$800 million.

PETROLEUM NEWS • WEEK OF NOVEMBER 23, 2014 11

O U R P A S S I O N I S

EXPLORATION

EXPLORATION & PRODUCTIONBP using robotics for EOR rock tests

According to a BP newsletter the company has implemented a robotic system

for testing enhanced oil recovery, or EOR techniques, for increasing oil recovery

rates from oil fields.

There are a variety of methods that can be used to entice as much oil as possi-

ble into production wells from reservoir rocks such as porous sandstones.

Techniques include the alternating use of waterflood and miscible injectant, and

the injection of low salinity water into the reservoir. Miscible injectant is a mix-

ture of natural gas and natural gas liquids that acts as a solvent, clearing out oil

from pores spaces, so that water can then flush the oil from the reservoir.

But the precise EOR configuration that will provide optimum results in a par-

ticular situation depends on the properties of the reservoir rock involved, as well

as on the type of oil. The development of a new EOR technique and the evalua-

tion of the technique in different reservoir settings depends on extensive labora-

tory testing. In particular BP uses a technique referred to as core flood for a test-

ing program of this type. In this technique water and gas are injected into oil-bear-

ing rock samples from a field reservoir, with the testing carried out under condi-

tions that simulate reservoir pressures and temperatures.

Continuous testingApparently the implementation of BP’s new robotic appliance enables core-

flood testing to operate continuously, 24 hours a day, seven days a week, upping

the number of core-flood tests carried out per year from a few dozen to several

hundred. BP anticipates that this acceleration of the testing program will greatly

shorten the time taken to evaluate new EOR techniques, potentially cutting the

time to deployment by at least 50 percent.

“The EOR technologies being developed by BP are vitally important to help

increase global oil supplies,” said Ahmed Hashmi, BP’s head of upstream tech-

nology. “We believe this step-change in our core flooding capability will hugely

improve the speed and efficiency with which we can deploy new technologies to

recover more oil from reservoirs.”

—ALAN BAILEY

FACILITIESConocoPhillips asking for target practice

In an unexpected byproduct of increased development, ConocoPhillips Alaska

Inc. is asking for permission to use two North Slope gravel mines as temporary

shooting ranges.

The company recently applied for a land use permit to use Mine Site C and

Mine Site E for summer target practice. “(ConocoPhillips) will need the flexibil-

ity to move around both mine sites due to change in activity levels at the pit,”

Environmental Coordinator Samuel Widmer explained in an application to the

Division of Mining, Land and Water.

The permit would run from December 2014 to December 2019, although the

company only intends to use the gravel mines for target practice during the sum-

mer, and, even then, only until it finishes training 52 security personnel, accord-

ing to the application.

The target practices “usually” occur on the weekends, according to Widmer.

He said that ConocoPhillips lays a “bullet tarp” over the practice area and recov-

ers all shells and casings. “When target practice is underway, the area where the

practice is happen will be closed,” he wrote. “This is announced over the radios

to all the operators on the slope.”

The Division of Mining, Land and Water is taking comments through Nov. 28.

—ERIC LIDJI

Third oil delivery from Arctic offshoreRussian oil and gas company Gazprom Neft has announced the third delivery

of crude oil from the Prirazlomnoye field, offshore in the Pechora Sea. An ice-

class oil tanker delivered the oil from the field’s concrete and steel walled plat-

form “to consumers in northwest Europe,” Gazprom has said.

The field uses two tankers, specifically built for the Prirazlomnoye project,

each with deadweights of 70,000 tonnes and using a “double action” design, in

which a ship travels forward through open water but reverses through ice, with the

ship’s propellers carving open the ice as necessary. According to the Offshore

Technology website and other sources, the tankers ship the Prirazlomnoye oil

1,100 kilometers west to the floating Belokamenka terminal in Kola Bay, near

Murmansk, in the southern Barents Sea.

Gazprom says that shipments from the field have delivered 200,000 tonnes of

oil in 2014. Field production started in December 2013 from a single well — a

second well should come on line at the end of 2014, with further wells planned

for 2015.

The company says the design of the platform includes a safety margin that

“vastly exceeds actual loads.” Prior to loading into tankers, produced oil is stored

in tanks in the platform’s caisson, using a storage method that excludes air from

the tanks, thereby avoiding the formation of an explosive mixture. A zero dis-

charge system avoids the need to dump drilling and other waste into the sea, with

waste either being injected into the subsurface through a disposal well, or being

transported to shore, Gazprom says.

—ALAN BAILEY

INTERNATIONAL

State files opposition to US water ruleThe state of Alaska has submitted comments opposing a proposed Environmental

Protection Agency rule defining “the Waters of the United States” under the Clean

Water Act. The state, saying that the rule would unlawfully place most of Alaska’s

waters and lands under the control of the EPA and the Army Corps of Engineers, has

asked the two agencies to withdraw the rule.

“The proposed rule would significantly expand EPA’s reach onto state, local, and

private lands under Clean Water Act

regulation,” said Gov. Sean Parnell in a

Nov. 15 statement. “This proposed rule

not only federalizes land use decisions

for state, local and private landowners, it

places them under threat of fines and

penalties up to $72,500 a day and jail

time.”

EPA introduced the proposed rule in

the spring in an attempt to clarify the

murky and thorny question of what water bodies are subject to federal jurisdiction,

and hence to federal permitting. And at its core, the concept of U.S. waters is straight-

forward: They are waters that could be used for interstate or foreign commerce,

including traditional navigable waters and the territorial seas around the country. But

the water-flow linkages between navigable waters and the tributaries and wetlands

that feed them lead to the possibility of pollution from some inland water body reach-

ing a navigable water channel. As a consequence EPA wants to spread the federal

jurisdiction net far and wide over any water that might connect in some way with a

navigable waterway.

The proposed rule, while praised by environmental organizations as providing

needed environmental protection, has met with vociferous opposition from those

who see the rule as an example of federal permitting overreach.

Parnell said that a bill that would stop the EPA’s action is stalled in Congress,

passed by the House of Representatives but not picked up by the Senate.

The public comment period for the proposed rule ended on Nov. 14 after twice

being extended.

—ALAN BAILEY

GOVERNMENT

EPA introduced the proposed rulein the spring in an attempt toclarify the murky and thorny

question of what water bodies aresubject to federal jurisdiction, and

hence to federal permitting.

12 PETROLEUM NEWS • WEEK OF NOVEMBER 23, 2014

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Oil Patch BitsPacific Alaska Lumber brings Zigma to Alaska

“Pacific Alaska Lumber has signed an agreement with Zigma Ground Solutions”, saidJohn Horjes, PAL director of business development. “PAL is the newest North American dis-tributor, and will stock ‘TuffTrak XL’ and ‘Liberty mats’ in Seward, Alaska.” The Seward facil-ity is “multifunctional,” providing truck and rail delivery to all points local and north, whilemaintaining barge deployment synergies, ready to serve other locations in Alaska.

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Pacific Alaska Lumber provides materials to all locations in Alaska, and specializes infull container and truckloads. For more information visit www.zigmagroundsolutions.comor www.pacaklumber.com.

Calista Corp. provides first-ever fund dividendCalista Corp.’s board of directors has approved the first-ever Akilista Fund dividend. The

total distribution is $1.62 million. This investment fund distribution supplements dividendsbased on Calista’s operations. Including Calista’s operational dividend mailed in April, thetotal dividend for the year is $6.27 million.

At 12,900 individuals, Calista has one of the largest populations of shareholders amongthe Alaska Native corporations. This Akilista Fund distribution equates to $1.22 per share.Checks were expected to be mailed out by the close of business Nov. 14.

“Calista’s Board of Directors established this investment fund to provide a perpetualand sustainable source of dividends for our Shareholders,” said Calista Corp. Board ChairWillie Kasayulie. “The Board and Calista management made a specific goal to provideShareholders with two dividends per year.”

In early October, Alaska Business Monthly’s annual Top 49ers luncheon recognizedCalista as the eighth largest Alaskan-owned business based on revenues. Since inception,Calista has provided more than $26.2 million in dividends including this distribution.

Editor’s note: All of these news items — some in expanded form — will appear inthe next Arctic Oil & Gas Directory, a full color magazine that serves as a marketing toolfor Petroleum News’ contracted advertisers. The next edition will be released in March.

PETROLEUM NEWS • WEEK OF NOVEMBER 23, 2014 13

how important that is to the long-term

future of the state, is do something that

is very hard for elected officials to do,

which is to think beyond a two- and

four-year cycle. That means taking steps

necessary now to be in a position to

withstand those kinds of commitments

should we move forward with an FID

(final investment decision). Some of

those steps were taken, quite honestly,

by moving $3 billion from the constitu-

tional budget reserve into the pension

funds. It may seem counterintuitive but

that really aids us in our ability to invest

in a gas pipeline because it takes care of

an obligation that we have. It’s taking

care of a debt we have on the books,

while it prepares us to have the financial

resources to invest in the pipeline. We

will be viewed as good credit. We honor

contracts. We take care of our debts.

Doing those things now, getting our

financial house in order, means we’ll be

able to afford the investment and enter

into things we need to enter into.

Petroleum News: Can you think ofanother example that speaks to what youjust noted?

Rodell: I think creating the certainty

for the producers under SB 21 definitely

assisted with that because it allowed our

three partners, who are putting up 75

percent of the cost for this project, to

have a more predictable income stream

themselves and manage their own finan-

cial commitments. It aligned all four of

us from that standpoint, no question.

And we will continue to look for oppor-

tunities to set that stage so we are ready

make that commitment, so that we can

make the commitment because it’s the

right or wrong thing for the state, not

because we don’t have the money

because we did something we should not

have done.

Petroleum News: So there are a lot ofmoving parts that may seem unrelated toresource development that actually speakdirectly to resource development?

Rodell: If you think about it from

your own personal finance management,

it’s like talking about your credit score,

cleaning it up, making sure your

accounts are up to date, and debts are

paid before you make a big purchase by

entering into a mortgage or buying that

boat you’ve had your eyes on for years.

It’s the same thing here. What should we

be doing now, recognizing we’ve made a

strong investment in oil and gas through-

out our history, not just with SB 21 or

SB 138? We have provisions, lease

expenditures, and we know they impact

revenue to the state in the near term and

those lease expenditures generate addi-

tional production which means we see

revenue further down the road, so what

kinds of things can we be doing to man-

age through this time period because we

made these long-term investments, and

get everybody to see the longer view

picture, which is the biggest challenge.

Petroleum News: So do you see yourwork, at its essence, as maintaining thestate’s credit score, granted it’s a lotmore than that?

Rodell: Very much so. We don’t write

budgets and we don’t project deficits,

but we do project revenue. Having said

that, we manage the financial resources

of the state. It’s important that we man-

age wisely and we give legislators and

the governor all the information that they

need to balance all of the demands that

the state has and will continue to have.

Petroleum News: So when you thinkof a project that might be $45 billion andit might be $65 billion, that can be moredaunting when you are a prospectivepartner and not just an entity that has tofoster a healthy business environment.

Rodell: In many ways, we are break-

ing new ground with this partnership.

And it is a different view than we’ve had

in the past whether it’s to foster an envi-

ronment or just to be done by the private

sector, or do it ourselves and try to get

the other parties to come to the table.

Both of those efforts taught us many les-

sons.

This is a hybrid. We are a full partner

with the producers. We are not doing it

all on our own. We are hoping that they

will show up. We are creating a climate

by being an investor in the climate our-

selves, putting our name and our money

at risk along with the producers. For the

first time we are all sitting at the table

trying to push this thing forward.

Petroleum News: Have you been ableto look outside to other regions or coun-tries for any kind of blueprint?

Rodell: Yes and no. I think we do

look at various examples of things that

have been done around the world,

whether it’s Australia or Russia, for les-

sons learned, but there is no project out

there that matches the size and scope of

this in its entirety. So there are bits and

pieces of it whether it’s an LNG plant or

a three-train plant that may teach us les-

sons about cost overruns. But when we

put it all together, we are breaking new

ground.

Having the three largest LNG produc-

ers in the world — world class compa-

nies in Conoco, BP and Exxon — sitting

next to me on this means that all of those

lessons are being brought to the table.

Quite honestly from the state’s perspec-

tive, we have our lessons as well and

bring those to the table.

Petroleum News: One of those lessonsfor the state might be found in CookInlet with Furie. What lessons can begleaned?

Rodell: I think it speaks to make sure

we complete our due diligence and dig

in with questions. That’s probably the

biggest lesson, not that the setup was

incorrect. We need to make sure we so

some firm work there.

Petroleum News: Do you see CookInlet becoming your export hub?

Rodell: Or Cook Inlet becomes the

gas supplier for in-state needs. It wasn’t

that long ago that brownouts were being

discussed. Now we’ve got a great supply

of gas in Cook Inlet. It’s really a matter

of understanding what’s going on in cer-

tain places.

Petroleum News: Let’s touch on theArctic for a few minutes. There’s talkabout necessary investment for thingssuch as ports and other infrastructure. Isthat on your radar as well? There arealready a lot of projects being reviewed.

Rodell: I’m not on the forefront of

those discussions. I’m sure Revenue will

be involved in those discussions as they

become more of a reality at some point

and discussions of how they get

financed. We will have to prioritize from

a couple of different standpoints. What is

the commitment to the state in terms of

what does it mean for jobs, what does it

mean for revenue, what does it mean for

economic activity within the state. So

some of these projects have great GDP

impact and they are generating revenue.

We have a ton of economic activity that

isn’t generating revenue for the state.

You have to look at what the end mis-

sion is for some of this. There has to be

an overall global mandate. So when I

was talking about some projects lending

themselves to other projects happening,

that creates a different consideration than

if it’s a standalone mega project that

doesn’t generate additional support to

other things happening.

For example, we look at the gas line,

AKLNG, and it’s moving forward on the

time frame that we all expect it to move:

we break ground in 2018/2019 and first

gas come in 2024/2025.

As we are moving through that and

we are considering a deepwater port out

in Northwestern Alaska and they have a

micro receiving center for LNG they

want to add to it. That will develop a

mining resource of some type. Now we

have sort of linked projects together and

we need to figure out how to stage gate

them so that when first gas is coming

through in 2025 that port is lined up and

that mine is ready to go. Part of it is not

just making the commitment, but staging

the commitment in such a way that if gas

doesn’t go, and we move away from it,

then that project doesn’t go either

because it doesn’t make sense for that

other project to go.

I think we just have to have what I

call a global strategy, laying things out to

see how they are interrelated. But if a

deepwater port doesn’t do anything but

serve as a port where we bring in goods

and services, that’s important, but it

doesn’t have the same spinning effect.

Petroleum News: You talked abouttrying to create a web of projects wherethey are related, do you ever see a timewhere some of Alaska’s industries now atodds with other another, projects sud-denly connect the two?

Rodell: Yeah, I would hope so. I think

there is always an inter relationship and

the challenge for Alaska is we are such a

diverse state geographically. You really

see it when you’re out traveling and you

see what different industries mean to dif-

ferent parts of the state. Recognizing the

challenge that we have at the state level

to bring all industry up and to float all of

these things up so people can succeed is

a huge challenge. I think there will be a

time when they come together where

they would normally be at odds. l

continued from page 3

RODELL Q&A

such as wind power, into its system.

Municipal Light & PowerMark Johnston, manager of Municipal

Light & Power’s regulatory department,

also picked up on the question of whether

the EPA would credit the Alaska utilities

for the energy generation efficiencies that

they had been achieving after 2012.

Johnston questioned the application of the

EPA rule in Alaska, given that carbon

dioxide emissions from power generation

in Alaska only account for about 7 per-

cent of the state’s total emissions. That

compares with power generation emis-

sions amounting to about 34 percent of

total emissions across the nation as a

whole, he said.

The utilities need more time to evalu-

ate the impacts on system reliability and

electricity rates of potential changes to

the power generation arrangements in

response to the EPA rule, Johnston said.

Golden ValleyGolden Valley Electric Association,

the Fairbanks-based electric utility,

obtains some of its power from a coal-

fired power station at Healy, on the north

side of the Alaska Range. Golden Valley

is also in the process of bringing a moth-

balled second coal-fired plant on line at

Healy. One question that the RCA has

raised is whether EPA’s second building

block, the replacement of relatively car-

bon-intense plants, could be achieved by

phasing out the coal-fired plants and

instead delivering power to Fairbanks

from efficient combined-cycle, gas-fired

plants in Southcentral. Power would need

to be shipped along a power transmission

line that connects Southcentral to

Fairbanks.

Mike Wright, Golden Valley’s vice

president of transmission and distribu-

tion, told the commission that shifting his

utility to the use of Southcentral gas-fired

power would put the utilities service area

“on a 350-mile extension cord.” And,

while the existing transmission intertie

between Southcentral and Fairbanks had

proved reliable over the years, the

extreme cold in the Interior winter drives

a need for highly dependable power sup-

plies, Wright said.

In written comments, Chugach

Electric said that the replacement of coal-

fired power from Healy by gas-fired

power from Southcentral would require

the installation of a second transmission

line to the Interior and either an upgrade

to the old Beluga power station or the

construction of a new gas-fired facility.

Wright also questioned EPA’s estimate

for carbon dioxide emissions at Healy,

saying that the agency had used an emis-

sions formula rather than the actual emis-

sions data for the operating coal-fired

plant, and that the agency had not consid-

ered emissions from the second plant.

And, were Golden Valley to have to shut

down these plants, the utility, left with

stranded assets worth around $450 mil-

lion, would have to substantially increase

its electricity rates.

Renewables?In addition, while Golden Valley does

have the ability to add new renewable

energy sources to its power generation

portfolio, the impact on its electric rates

of the use of more renewable energy

would need to be considered, Wright said.

In written comments, Golden Valley said

that its ability to connect a renewable

energy facility to its system would

depend on the cost of the energy, the cost

of connecting the facility to the power

grid and the cost of integrating the energy

into the grid.

In terms of energy efficiency, the

fourth of EPA’s building blocks, Golden

Valley has been operating energy efficien-

cy programs since 1992, Wright said. In

its written statement the utility said that

because most of its members have already

implemented energy efficiency measures

it may not be possible to implement fur-

ther measures, as suggested by EPA.

Individual residential power loads have

been dropping as a result of improved

energy efficiency, the utility said.

In written comments, Chugach

Electric said that, while its per-consumer

load has been steadily dropping thanks to

various energy efficiency improvements,

the characteristics of that load provide

only limited abilities for demand-side

efficiency management.

Wind powerEthan Schutt, senior vice president for

land and energy for Cook Inlet Region

Inc., argued for the implementation of

more wind power on the Railbelt grid,

saying that in the grid there is a lack of a

coordinated response to the use of avail-

able tools for integrating the fluctuating

wind power. Cook Inlet Region Inc. built,

owns and operates a wind farm on Fire

Island near Anchorage and wants to

expand that facility.

Alaska Environmental Power, an alter-

native energy company based in

Fairbanks, submitted an RCA filing

expressing frustration at what it sees as

obstacles to independent power producers

bringing renewable energy to the Railbelt

grid. The company has been trying to per-

suade Golden Valley to purchase power

from a wind farm at Delta Junction. l

continued from page 7

EMISSIONS RULE

14 PETROLEUM NEWS • WEEK OF NOVEMBER 23, 2014

Shrunken unitThe Division of Oil and Gas formed

the 1,480-acre unit over segments of four

leases in September 2011. The company

had wanted a unit covering some 8,769

acres. Instead, the state restricted the unit

boundaries to the drainage radius of the

Placer No. 1 well, segmented the addi-

tional acreage and extended the terms of

those segmented leases. The unit size

approved in the Nov. 13 decision is the

8,769 acres originally requested.

The unit agreement set deadlines for

ASRC Exploration to re-process seismic

data by the end of 2011 and to drill a fol-

low-up well or re-enter Placer No. 1 by

June 2013. After reprocessing the seis-

mic, the company asked to expand the

unit to its original size.

The Division of Oil and Gas denied the

request. ASRC Exploration appealed the

denial to the Department of Natural

Resources. That appeal is the basis for the

current decision.

The unit went into default when ASRC

Exploration failed to drill the exploration

well by June 2013. The state gave the

company a year to cure the default by

drilling the well.

Potential joint ventureIn a private meeting with the state on

September 2013, officials from ASRC

Exploration and Brooks Range Petroleum

Corp. offered four options for exploring

Placer. Brooks Range Petroleum became

involved because the two companies

believed the Placer unit might extend into

Brooks Range Petroleum’s Appaloosa

prospect, located to the south.

All four proposals involved ASRC

Exploration farming-out exploration to

Brooks Range Petroleum. The explo-

ration would have occurred in the pro-

posed expansion acreage.

To allow that plan to proceed, ASRC

Exploration asked the state to rule on the

appeal.

The Department of Natural Resources

sent the case back to the division in

September 2013, asking the division to

approve the expansion, pending certain

conditions. Those conditions were:

drilling an exploration well by 2014,

keeping the existing five-year term of the

unit, posting a performance bond and pro-

viding a copy of the farm out agreement.

The Division of Oil and Gas agreed. A

November 2013 ruling gave ASRC

Exploration until Dec. 15, 2013, to post

the bond and provide the agreement.

ASRC Exploration never compiled, even

after the division extended the deadline

twice, according to the state.

Near terminationAs such, the Placer unit remained in

default.

When ASRC Exploration failed to

cure the default by drilling, the state

solicited potential remedies for curing the

default, which is one of the final steps

before unit termination.

In an August 2014 hearing, ASRC

Exploration “insisted” that the state

expand the unit and allow the company to

drill an exploration well in the expansion

acreage. The company proposed drilling

by May 31, 2016. After the meeting, the

company submitted a new plan of explo-

ration. The state denied the plan. The

company appealed the denial.

The Department of Natural Resources

sent the case back to the division in

October, this time requiring an explo-

ration well by May 2016 and a $2.5 mil-

lion performance bond.

Regional explorationThe Placer unit is part of larger efforts

to explore the region between the

Kuparuk River and Colville River units,

an undeveloped tract known as the “bil-

lion dollar fairway.”

To the south, Brooks Range Petroleum

is developing the Mustang field at the

Southern Miluveach unit. The state

recently terminated the company’s

Kachemach unit, which was between

Southern Miluveach and Placer and had

been discussed as a corollary to Placer.

To the north, Repsol intends to drill

three exploration wells this winter. Earlier

this year, Repsol proposed the Tapqaq

unit, which would have included some of

the proposed Placer unit acreage. The unit

application has yet to be published for

public comment.

To the east, ConocoPhillips Alaska

Inc. is planning an appraisal program at

the Palm satellite at Kuparuk River unit

Drill Site 3S. The appraisal could lead to

a new drill site.

—ERIC LIDJI

continued from page 1

PLACER EXPANSION

bound for South Africa.

A four-year sagaThe now-bankrupt independent

Buccaneer Energy Ltd. formed Kenai

Offshore Ventures in late 2010 to pur-

chase a jack-up drilling rig using short-

term tax-exempt bonds. The company

wanted to use the rig to explore offshore

oil and gas prospects in the Cook Inlet.

As the agency responsible for issuing

the bonds, AIDEA became involved the

project.

The bond never occurred, but AIDEA

remained interested. The project fit the

goals of a 2009 strategic plan calling for

the public corporation to actively diversi-

fy its investments.

So AIDEA partnered with Buccaneer

and Ezion to buy the rig.

In mid-2011, Kenai Offshore Ventures

purchased the Transocean Adriatic XI

jack-up rig and renamed it “Endeavour —

Spirit of Independence.” Toward the end

of the year, the AIDEA board approved a

deal to invest as much as $30 million in

the Endeavour project.

By contributing some $23.6 million to

Endeavour, AIDEA became a preferred

member of Kenai Offshore Ventures.

Buccaneer and Ezion invested some

$30.4 million to the project as common

members. Oversea-Chinese Banking

Corporation (OCBC) Ltd. invested the

remaining $66 million needed to fund the

estimated $120 million project.

Rig drilled Cosmopolitan No. 1After some delays, Endeavour was

used to drill the Cosmopolitan No. 1 well

for Buccaneer. The well discovered oil

and gas. But soon after, Buccaneer sold

its share in Cosmopolitan and sold its

stake in Kenai Offshore Ventures to

minority partners.

The move was an effort by Buccaneer

to improve its financial situation. But

even with the sales, Buccaneer eventually

filed for bankruptcy protection in late

May 2014.

In early feasibility studies, AIDEA

identified 22 wells in the Cook Inlet basin

that might require the use of a jack-up rig.

These were technical candidates, not

expressions of interest. At the end of the

day, Kenai Offshore Ventures was unable

to find any takers.

“Our KOV partners’ investment in the

Endeavour was good not only for Cook

Inlet, but resulted in their recent and

major investment on the North Slope:

partnering with AIDEA to jointly finance

and own an oil and gas production and

processing facility at the Mustang Field,”

AIDEA Director of Project Development

and Asset Management Jim Hemsath said

in a statement, referring to AIDEA’s more

recent investments with Brooks Range

Petroleum Corp. “We remain bullish on

Cook Inlet, and are in discussions on

potential oil and gas production facilities

in addition to a potential new rig for the

Inlet.”

Even with the departure, Cook Inlet is

still home to a jack-up rig: the Spartan

151, which has been drilling at the

Kitchen Lights unit on behalf of Furie

Operating Alaska LLC.

When AIDEA was in negotiations with

Buccaneer to buy Endeavour, the Furie

predecessor Escopeta Oil Co. worried

about having competition from the public

sector. l

continued from page 1

JACK-UP SALE

PETROLEUM NEWS • WEEK OF NOVEMBER 23, 2014 15

nanaworleyparsons.com

Solutions for Alaska’s onshore and offshore resourcedevelopment.

Local expertise and global resources, from concept to operational support.

Project Delivery

Arctic Design

Modularization

Logistics

ENVIRONMENT & SAFETYSharp decline in polar bear population

An international team of scientists led by researchers from the U.S. Geological

Survey has found that the polar bear population in the southern Beaufort Sea

declined by about 40 percent between 2001 and 2010, the USGS has reported.

The scientists attribute much of the decline to a low survival rate of polar bear

cubs between 2004 and 2006.

“Of the 80 cubs observed in Alaska from 2004 to 2007, only two are known to

have survived,” said Jeff Bromaghin, USGS research statistician and lead author

of the study.

Despite some improvement in the survival rates of both young bears and

adults, starting in 2007, the survival rate of juvenile bears declined during the

entire study period. By 2010 the bear population had stabilized at about 900 ani-

mals, the USGS says.

Bromaghin says that the reason for the low survival rates remains unknown,

with a combination of different factors possibly contributing to the population

decline. One possible culprit is a lack of adequate access to seals, the bears’ pre-

dominant prey. During the fall open water season, many bears stay on the sea ice

as it retreats to an ever diminishing sea ice extent, leaving the bears at consider-

able distances from shore areas that seals are thought to predominantly inhabit,

USGS says. In the winter, the increasingly thin and mobile sea ice is more sus-

ceptible to breaking up and rafting than in past years, leading to jumbled ice con-

ditions that may make the capture of seals more difficult, the agency says.

Of 19 Arctic polar bear populations, four, including the southern Beaufort Sea

population, are thought to be in decline, five are stable and one is increasing —

there is insufficient data to determine population trends in the remaining popula-

tions, USGS says.

—ALAN BAILEY

the future development of the oil field,”

the company wrote in its filings.

Umiat 23H was the first horizontal

well to be drilled and flow tested at the

known oil field in the foothills of the

Brooks Range Mountains. The flow test

produced a peak rate of 800 barrels per

day and a sustained rate of 250 barrels per

day, according to Linc.

Those results convinced Linc to pursue

development. The company is still work-

ing through early environmental studies

but has suggested a 70-well development

plan.

Back in September, Linc said it would

make a decision about the sale by the end

of the year. Any sale of such “core assets”

would require the approval of sharehold-

ers.

—ERIC LIDJI

continued from page 1

UMIAT SALE

BUC

CA

NEE

R E

NER

GY

The Endeavour drilling rig

ably reflects the amount of vessel traffic

in these regions. Cook Inlet and Prince

William Sound come fairly high in the

list. The Beaufort and Chukchi seas come

in the middle, while the least risky

regions are Western Alaska, Bristol Bay

and the Kotzebue Sound/Hope Basin.

Moving forward to 2025, the Beaufort

Sea jumps to the top of the list, followed

by the Aleutians. This result reflects an

expectation of increased oil exploration

and production in the Beaufort, and of an

increase in vessel traffic around the

Aleutians. Curiously, the Chukchi Sea

remains in the middle of the list, with the

analysis assuming oil and gas develop-

ment in this region but a relatively low

oil-spill incident rate.

Worst case discharge risksLooked at from the perspective of cur-

rent worst case discharge risks, the

Aleutian region moves down toward the

middle of the risk ratings, with other

regions remaining at somewhat similar

relative risks to the maximum-most-prob-

able-discharge ratings. In 2025 the

Beaufort Sea moves to the top of the risk

table, based on assumptions about future

oil industry activities, with the Aleutian

region coming second. However, the

inferred worst-case risk levels for 2025

drop somewhat in some regions, on the

assumption of improved oil spill mitiga-

tion measures by that time.

The NOAA report recommends further

study into the oil spill risk issues relating

to Southeast Alaska, the Aleutians, the

Beaufort Sea, the Kodiak/Shelikof Strait

and Cook Inlet, the regions identified as

having relatively high risk.

“In particular (oil) trajectory and fates

modeling would be a natural next step to

this study to examine the magnitude of

potential consequences from oil spills

originating from the high relative risk

regions,” the report says. l

16 PETROLEUM NEWS • WEEK OF NOVEMBER 23, 2014

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Enbridge executives said the hopes of

bringing Northern Gateway on stream in

2018 are “quickly evaporating.”

More seriously, the project is being

swamped with court challenges from abo-

riginal and environmental groups and

costs which Enbridge has conceded will

be “substantially higher” than its previous

estimates because of a more detailed

engineering evaluation and costs associ-

ated with meeting 209 conditions

imposed by the National Energy Board.

Competing proposalsThere is also the possibility that other

pipeline proposals — TransCanada’s

Keystone XL and Energy East and Kinder

Morgan’s Trans Mountain expansion,

which offer combined capacity of 2.5 mil-

lion bpd — might start eating into

Northern Gateway’s commercial backing.

In a glowing tribute to Holder,

Enbridge Chief Executive Officer Al

Monaco praised her for guiding “one of

the most difficult projects in Canadian his-

tory through to regulatory approval, repre-

senting Enbridge and its partners with

integrity. She built trust with communities

by listening to their concerns and demon-

strating Northern Gateway’s commitment

to building a safe project that protects the

environment.”

Holder was put in charge of the project

when it no longer had much, or any hope

of swaying public opinion, Enbridge hav-

ing apparently failed in the early years of

Gateway to grasp that opposition in British

Columbia was unlike anything the compa-

ny had encountered in Alberta.

With Northern Gateway floundering,

Enbridge ended the summer by launching

a costly — the company is not saying how

costly — campaign through newspapers,

Google, social media, digital displays, tel-

evision and elevators to build on its “posi-

tive reputation.”

Using the theme Life Takes Energy, it

seized what Communications Vice

President D’Arcy Levesque said was an

“opportunity to refocus the conversation

that is taking place in North America about

the role of energy.”

Rather than flogging the tired message

about the economic benefits of energy,

which many viewed as merely a defense of

huge corporate profits, Enbridge tried

pitching the role of energy in the “amazing

moments that define our quality of life” —

such as a “baby’s first bath, a car ride with

your dog, an unforgettable dinner or the

trip of a lifetime.”

Whether or not that worked is not clear,

but Enbridge is still faced with figuring out

what, if anything it can do to win anyone

over to Northern Gateway.

Environmentalist, First Nationsopposition

Environmentalists are becoming more

entrenched than ever, having tasted suc-

cess in their campaigns to stall Keystone

XL and Northern Gateway — tactics they

are now applying with similar vigor to

Energy East and Trans Mountain.

First Nations are equally resolved,

unless there is room and a willingness by

Enbridge to transfer an even greater share

of Northern Gateway’s wealth, through

jobs and economic benefits.

That challenge became more daunting

in late September when the Federal Court

of Appeal granted leave to the Gitxaala

Nation to apply for a judicial review of the

project’s approval, insisting the Canadian

government failed to consider the

Gitxaala’s aboriginal rights and title.

There are at least eight other separate

legal actions being launched against

Enbridge by various First Nations.

The scope of what confronts Northern

Gateway has already been acknowledged

by new project President John Carruthers,

who, before he got the assignment, told a

business audience in Calgary that his focus

was on building support among First

Nations along the pipeline right of way.

“I’m not fussed on what (the startup)

date is. I’m more fussed on whether we

can have the support we need to go ahead,

so it’s positive for all people of Canada,

including aboriginal people.

“That’s going to take time and it’s

going to take the time it takes,” he said. l

Leader In All We Do

Proud members of the Doyon Family of Companies

continued from page 6

SPILL REPORT

continued from page 1

GATEWAY LEADERThere is also the possibility that

other pipeline proposals —TransCanada’s Keystone XL andEnergy East and Kinder Morgan’sTrans Mountain expansion, which

offer combined capacity of 2.5million bpd — might start eating

into Northern Gateway’scommercial backing.