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

l N A T U R A L G A S

l N A T U R A L G A S

page5

Gara concerned about contractresult; wants stronger legislation

Vol. 19, No. 16 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of April 20, 2014 • $2.50

CO

URT

ESY

BP

Prudhoe Bay Flow Station compressor replacement project skidsunder construction at NANA Big Lake facility, with Prudhoe fabrica-tion site manager Dan Donaldson of Udelhoven and Will Briar, BP’sAlaska fabrication manager. See story on Prudhoe Bay turnarounds,eastern area compressor replacements on page 13.

Compressor replacements

Hilcorp goes bigMajor gas exploration program follows disappointing oil exploration results

By ERIC LIDJIFor Petroleum News

Even though its oil exploration activities last

year yielded no commercial discoveries,

Hilcorp Alaska LLC plans to drill as many as six

exploration wells at the Ninilchik unit this year to

follow up on recent gas discoveries made at the

coastal Cook Inlet unit.

The local subsidiary of the Texas-based inde-

pendent also plans to drill two exploration wells

from a new pad at the Deep Creek unit located far-

ther inland from Ninilchik.

The company is also planning workovers and

development drilling across its portfolio, but an

eight-well program would be the busiest in the

Cook Inlet since Marathon Oil Co. drilled nine

development wells in 2008 and one of the busiest

Cook Inlet exploration programs in decades. By

comparison, the Alaska Oil and Gas Conservation

Commission issued nine drilling permits for explo-

Gas exports to restartDOE issues new export license for ConocoPhillips Kenai Peninsula LNG facility

By ALAN BAILEYPetroleum News

The U.S. Department of Energy has authorized

the renewal of a license for the export of lique-

fied natural gas from ConocoPhillips’ LNG facility at

Nikiski on the Kenai Peninsula to countries that do

not have free-trade agreements with the Unites

States, ConocoPhillips said April 14. In February the

agency issued a similar license for the export of LNG

to countries that do have U.S. free-trade agreements.

Both licenses run for a period of two years and, indi-

vidually or in combination, allow for the export of up

to 40 billion cubic feet per day of gas.

Start in the springConocoPhillips says that, with the licenses having

now been issued, it plans to resume LNG exports

from the Cook Inlet basin in the spring. The licenses

allow the company to export both its own gas and gas

that it is shipping for other entities.

“ConocoPhillips had previously said that it would

consider pursuing a new export authorization if local

Cook Inlet area gas needs were met and there was

sufficient gas available for export,” ConocoPhillips

said in an April 14 press release. “During 2013, local

utilities executed gas supply agreements securing

their supply through at least the first quarter of 2018.

Treading carefullyImperial, partner with majority owner ExxonMobil, won’t be rushed into BC LNG

By GARY PARKFor Petroleum News

Imperial Oil has never been drawn by a herd men-

tality in building its Canadian operations and

shows no signs of changing that careful approach

when it comes to deciding on an LNG project for

British Columbia.

In partnership with its 70 percent owner

ExxonMobil, Imperial is putting out the word that a

final verdict on its WCC LNG project could be years

away.

Not that Imperial lacks the resources or the finan-

cial means to proceed, starting with its 540,000 net

acres of land prospects in the Horn River, Montney

and Duvernay formations of British Columbia and

Alberta which hold a reserve potential of 20 trillion

cubic feet.

Based on that resource, it has already secured a

National Energy Board permit to export 30 million

metric tons a year of LNG over 25 years.

But, from this point on it will take a thorough

approach to developing options for what it hopes

could be a “large-scale export opportunity,” led by

Chairman, President and Chief Executive Officer

Rich Kruger, who assumed his post last year after

see HILCORP PLANS page 18

see GAS EXPORTS page 19

see TREADING CAREFULLY page 19

... an eight-well program would be thebusiest in the Cook Inlet since MarathonOil Co. drilled nine development wells in2008 and one of the busiest Cook Inlet

exploration programs in decades.

Kruger is not swayed by those who believeLNG from Canada could fetch US$14-$18per thousand cubic feet in Japan or South

Korea.

Sale of Pioneer’s Alaska assets toCaelus closes; includes Oooguruk

Pioneer Natural Resources announced April 15 that it had

closed the sale of its Alaska subsidiary, including the

Oooguruk oil field, to Caelus Energy Alaska LLC for $300

million. And on the same day Caelus Energy also confirmed

the sale, saying that it had formed a strategic partnership with

Apollo Global Management, an international investment man-

agement company, for the Caelus investments in Alaska.

Apollo, in a press release announcing the agreement with

Caelus, said that its funds “have the opportunity” to invest up

to $1 billion dollars in Caelus “to develop the company’s

existing assets and to pursue acquisitions or other additional

investments.”

“We are excited to be working with Apollo to build a

world-class, Alaska-focused independent E&P business,

BC to share LNG returns withPrince Rupert area First Nations

The British Columbia government has added another plank

to its LNG platform by signing two revenue-sharing pacts

with First Nations in the Prince Rupert area.

The agreements with the Lax Kw’alaams and Metlakalta

communities demonstrate the government’s resolve to work

“together with First Nations and proposals for LNG success,”

said Premier Christy Clark.

The deals involve sharing a portion of provincial govern-

ment revenues from agreements related to the sale of Grassy

Point lands identified as potential sites for export facilities by

the Aurora LNG project operated by Nexen/China National

Offshore Oil Corp. and Australia’s Woodside Petroleum.

Aboriginal Relations Minister John Rustad said the com-

mitment by the two First Nations “will underpin the econom-

ic security of their communities ... and create greater certain-

ty for the First Nations, industry and government.”

see SUBSIDIARY SALE page 18

see REVENUE SHARING page 15

2 PETROLEUM NEWS • WEEK OF APRIL 20, 2014

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

14 Is North Slope shale oil really feasible?

10 Bill Richardson elected to Miller board

14 Legislature approves AGDC board change

11 Legislators mull infrastructure costs

12 DEC proposes Furie onshore facility approval

14 House Finance planning to amend Senate Bill 138

10 Alyeska questions ‘stray metal’ list

4 Montney entices Crew

6 BP continuing to evaluate heavy oil

EXPLORATION & PRODUCTION

15 Bill to replenish oil spill fund stalls

Legislation would raise per-barrel surcharge on oil outputfrom 4 cents to 7 cents; industry opposes hike as unfair

12 Feds considering Buccaneer IHA

Buccaneer requesting incidental harassmentauthorization for proposed offshore explorationin the upper Cook Inlet this year

13 BP works ahead for summer turnarounds

Company has work scheduled this year at 3 Prudhoe Bay facilities: Central Gas Facility, Gathering Center 2 and Flow Station 3 PIPELINES & DOWNSTREAM

NATURAL GAS

8 State partly OKs Oooguruk expansion

Agrees expanded Nuiqsut participating area is justifiedbut wants to see plan for more development drilling in additional acreage

9 Northern Gateway faces rival

First Nations, BC industrial giant unveil plans for C$18Benergy corridor to BC coast in bid to attract aboriginal participation

4 Pipeline takes double blow

Enbridge’s Northern Gateway project rejectedin non-binding Kitimat vote; First Nations groupformally opposes plan

LAND & LEASING

5 Gara concerned about contract outcome

Anchorage Democrat likes Alaska LNG project over in-state line; wants more instructions on negotiations in enabling legislation

8 Interior publishes mitigation strategy

Says new landscape-level approach to federal landmanagement will effectively reconcile developmentneeds with conservation

GOVERNMENT

FINANCE & ECONOMY

7 Henry Hub gas to average $4.44 this year

EIA says natural gas averaged $3.73 per million Btuin 2013; Brent averaged near $110 per barrel in March for 9th consecutive month

Hilcorp goes big

Major gas exploration program follows disappointing oil exploration results

ON THE COVER

BC to share LNG returns withPrince Rupert area First Nations

Sale of Pioneer’s Alaska assets to Caelus closes; includes Oooguruk

Gas exports to restart

DOE issues new export license for ConocoPhillips Kenai Peninsula LNG facility

Treading carefully

Imperial, partner with majority owner ExxonMobil, won’t be rushed into BC LNG

5304 Eielson Street • Anchorage, AK 99518 907.563.9060 • www.gdiving.com

COMMERCIAL DIVINGOFFSHORE SUPPORTMARINE CONSTRUCTIONENVIRONMENTAL SERVICESPROJECT MANAGEMENTLOGISTICAL SUPPORT

MORE THAN JUST A DIVING COMPANY

SIDEBAR, Page 4: Kinder Morgan on sales mission

PETROLEUM NEWS • WEEK OF APRIL 20, 2014 3

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

Alaska Rig StatusNorth Slope - Onshore

Doyon DrillingDreco 1250 UE 14 (SCR/TD) Prudhoe Bay DS 14-31, workover BPDreco 1000 UE 16 (SCR/TD) Prudhoe Bay MPE-24, workover BPDreco D2000 Uebd 19 (SCR/TD) Alpine CD3-316B ConocoPhillipsAC Mobile 25 Prudhoe Bay B-26C BPOIME 2000 141 (SCR/TD) Kuparuk 2K-29 ConocoPhillipsTSM 7000 Arctic Fox #1 Mobilization to Kenai ConocoPhillips

Kuukpik 5 Stacked out in Deadhorse Available

Nabors Alaska DrillingAC Coil Hybrid CDR-2 Kuparuk 2F-18 ConocoPhillipsDreco 1000 UE 2-ES (SCR-TD) Prudhoe Bay Available Mid-Continental U36A 3-S Prudhoe Bay AvailableOilwell 700 E 4-ES (SCR) Prudhoe Bay AvailableDreco 1000 UE 7-ES (SCR/TD) Kuparuk ConocoPhillipsDreco 1000 UE 9-ES (SCR/TD) Kuparuk ConocoPhillipsOilwell 2000 Hercules 14-E (SCR) Prudhoe Bay AvailableOilwell 2000 Hercules 16-E (SCR/TD) Prudhoe Bay Available Emsco Electro-hoist-2 18-E (SCR) Prudhoe Bay StackedEmsco Electro-hoist Varco 22-E (SCR/TD) Prudhoe Bay StackedTDS3Emsco Electro-hoist Canrig 27-E (SCR-TD) Prudhoe Bay Available 1050EEmsco Electro-hoist 28-E (SCR) Prudhoe Bay StackedOilwell 2000 33-E Prudhoe Bay Available Academy AC Electric CANRIG 99AC (AC-TD) Working for Repsol RepsolOIME 2000 245-E (SCR-ACTD) Oliktok Point ENIAcademy AC electric CANRIG 105AC (AC-TD) Working for Repsol RepsolAcademy AC electric Heli-Rig 106-E (AC-TD) Working for Repsol Repsol

Nordic Calista ServicesSuperior 700 UE 1 (SCR/CTD) Prudhoe Bay Drill Site 2-18 BPSuperior 700 UE 2 (SCR/CTD) Milne Point Well Drill Site F-30 BPIdeco 900 3 (SCR/TD) Kuparuk Well 3N-02 ConocoPhillips

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

North Slope - OffshoreBPTop Drive, supersized Liberty rig Inactive BP

Doyon DrillingSky top Brewster NE-12 15 (SCR/TD) Spy Island SP05-FN7 RWO, workover ENI

Nabors Alaska DrillingOIME 1000 19AC (AC-TD) Oooguruk ODSN-02 Pioneer Natural Resources

Cook Inlet Basin – Onshore

Kenai Land Ventures LLC (All American Oilfield Associates, labor Contract)Taylor Glacier 1 Kenai Loop Drilling Pad #1 Buccaneer Energy Ltd.

All American Oilfield AssociatesIDECO H-37 AAO 111 Kenai Yard Available

Aurora Well ServicesFranks 300 Srs. Explorer III AWS 1 Stacked out in Sterling Available

Nabors Alaska DrillingContinental Emsco E3000 273E Kenai AvailableFranks 26 Kenai StackedIDECO 2100 E 429E (SCR) Kenai StackedRigmaster 850 129 Kenai Available

SaxonTSM-850 147 Ninilchik Unit, Bartolowits pad Hilcorp Alaska

drilling Frances #1TSM-850 169 Swanson River Hilcorp Alaska

Cook Inlet Basin – Offshore

XTO EnergyNational 110 C (TD) Idle XTO

Spartan Drilling Baker Marine ILC-Skidoff, jack-up Spartan 151 Furie

Upper Cook Inlet KLU#1Cook Inlet EnergyNational 1320 35 Osprey Platform RU-1, workover Cook Inlet Energy

Hilcorp Alaska LLC (Kuukpik Drilling, management contract)Monopod A-17, workover Hilcorp Alaska LLC

Patterson UTI Drilling Co LLC 191 West McArthur River Unit #8 Cook Inlet Energy

Kenai Offshore VenturesLeTourneau Class 116-C, Endeavor Port Graham Buccaneer Energy Ltd. jack-up

Mackenzie Rig StatusCanadian Beaufort Sea

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

Central Mackenzie Valley

AkitaTSM-7000 37 Racked in Norman Well, NT Available

Alaska - Mackenzie Rig ReportThe Alaska - Mackenzie Rig Report as of April 17, 2014.

Active drilling companies only listed.

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

This rig report was prepared by Marti Reeve

Baker Hughes North America rotary rig counts*April 11 April 4 Year Ago

US 1,831 1,818 1,771Canada 212 235 156Gulf 52 46 47

Highest/LowestUS/Highest 4530 December 1981US/Lowest 488 April 1999Canada/Highest 558 January 2000Canada/Lowest 29 April 1992

*Issued by Baker Hughes since 1944

The Alaska - Mackenzie Rig Report is sponsored by:

JUDY

PAT

RICK

4 PETROLEUM NEWS • WEEK OF APRIL 20, 2014

Kay Cashman PUBLISHER & EXECUTIVE EDITOR

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Petroleum News and its supple-ment, Petroleum Directory, are

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

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FINANCE & ECONOMYMontney entices Crew

Fast-moving Canadian junior producer Crew Energy has solidified its position

in Western Canada’s Montney resource play by acquiring 48,000 net acres from

two unidentified parties for C$105 million, accompanying that deal with a shuf-

fle of other assets.

The Montney purchase is contiguous with existing Crew holdings of about

240,000 acres which contain petroleum initially-in-place of 45 trillion cubic feet

of natural gas and 7.8 billion barrels of oil and liquids.

Company Chief Executive Officer Dale Schwed said the purchase fits “like

integral pieces of a puzzle ... with Crew’s existing land base” and is part of his

company’s long-term plan to allocate capital to the Montney, which is rated as a

world-class resource.

The additional Montney assets produce 1,400 barrels of oil equivalent per day

(98 percent gas). The deal also includes 80 miles of pipelines.

Sale of Deep basin assetsAt the same time said it has sold almost 250,000 acres of Deep basin assets in

Alberta that produce 6,000 boe per day (75 percent gas) to Long Run Exploration.

That deal involves C$222 million in cash compensation, plus 400 bpd of heavy

oil production located in Crew’s operating area in Lloydminster, boosting Long

Run’s output to an expected 32,150 boe per day, growing to 34,500 boe per day

in 2015.

All of the acquired Montney lands are in what Crew has identified as a “wet”

hydrocarbon window, giving the company a net 88,000 acres in the “oil” window

and 152,000 net acres in the “wet” gas window.

Production from Crew’s core Septimus area in the Montney increased by 74

percent last year to about 10,500 boe per day and long-term projections point to

35,000 boe per day by 2018.

The Montney formation is viewed as a potential prime source of gas to supply

LNG projects.

—GARY PARK

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

Pipeline takes double blowEnbridge’s Northern Gateway project rejected in non-bindingKitimat vote; First Nations group formally opposes plan

By GARY PARKFor Petroleum News

Enbridge’s Northern Gateway pipeline

has taken two more beatings in the

court of public opinion, but the trouble-

plagued project has yet to face its most crit-

ical verdict that most industry observers

believe it will win.

For now the C$6.5 billion plan to ship

oil sands bitumen from Alberta to the deep-

water British Columbia port at Kitimat for

export to Asia is left reeling by the results

of a non-binding plebiscite in the resource

District of Kitimat and what is described as

a final rejection by a group of British

Columbia First Nations.

Regardless of how the non-binding

Kitimat vote is perceived among lawmak-

ers, the most critical decision is expected in

June when the Canadian government cabi-

net decides whether or not to accept the

recommendations of its regulators that the

project should be approved along with 209

conditions.

April 12 voteThe residents is Kitimat were given the

chance to vote April 12 on whether they

supported the recommendations of a Joint

Review Panel of the NEB and the

Canadian Environmental Assessment

Agency.

The ballot count was 1,793 opposed and

1,278 in support, a margin of 58.4 percent

to 41.6 percent.

Kitimat Mayor Joanne Monaghan said

“the people have spoken. That’s what we

wanted. It’s a democratic process.”

Kitimat is the proposed site of a two-

berth marine terminal for 525,000 barrels

per day of bitumen and a tank farm to store

the product before it’s loaded on tankers,

plus the import of 193,000 bpd of conden-

sate for delivery to Alberta where it would

be mixed with the thick bitumen to facili-

tate pipeline transportation.

Enbridge: ‘more work to do’Enbridge, which has been campaigning

for Northern Gateway over more than a

decade and has offered an equity stake in

the project to First Nations, said it won’t let

up in its efforts to win over the public.

The plebiscite result “shows that while

there is support for Northern Gateway in

Kitimat, we have more work to do,” said

Donny van Dyke, the company’s Kitimat-

based manager of coastal aboriginal and

community relations.

“Over the coming weeks and months

we will continue to reach out and listen to

our neighbors and friends so that Northern

Gateway can build a lasting legacy for the

people of our community,” he said.

Van Dyke said that as a long-time resi-

dent of northwestern British Columbia he

“passionately believes that Northern

Gateway is the right choice for Kitimat and

Kinder Morgan on sales mission

With Enbridge floundering in its

efforts to sway public opinion

towards its Northern Gateway

pipeline, Kinder Morgan is waging

an all-out campaign to make a case

for expansion of its Trans Mountain

system to 890,000 barrels per day

from 300,000 bpd.

To that end, the company’s

Canadian President Ian Anderson is

hitting the road to engage in face-to-

face meetings along the pipeline

right of way from the Alberta oil

sands to the Burnaby dock in Port

Metro Vancouver.

He has so far personally partici-

pated in at least 250 meetings with

residents, landowners, business oper-

ators, First Nations and environmen-

talists.

Anderson told the Vancouver Sun

that his company strongly believes it

must spend time talking to affected

parties and has taken that approach

since the C$5.4 billion venture was

officially launched 18 months ago.

see NORTHERN GATEWAY page 6

see KINDER MORGAN page 6

By STEVE QUINNFor Petroleum News

House Rep. Les Gara said he likes

the prospects of getting a natural

gas pipeline built to a liquefied natural

gas plant in Cook Inlet. But he’s not so

sure Gov. Sean Parnell’s Senate Bill 138,

plus the memorandum of understanding

signed with TransCanada and the heads

of agreement signed with North Slope

leaseholders ExxonMobil,

ConocoPhillips and BP will protect

Alaskans. Gara, an Anchorage

Democrat, sits on the House Finance

Committee, the last legislative commit-

tee of referral for the bill designed to

advance a project to the next stage:

charging the administration with negoti-

ating a project development contract

with leaseholders and TransCanada.

Between gas line hearings — and

they came to about three daily as the

session wound down — Gara sat down

with Petroleum News to discuss his

thoughts on the status of a project.

Petroleum News: Let’s start with ageneral question. As an aggregate — theMOU, the HOA and SB138 — what areyour general thoughts?

Gara: Well there is good and there is

bad. I have to decide whether the good

or the bad outweigh each other. The

good is that it’s better than what I call

the straw pipeline, the HB 4 in-state

pipeline that would deliver very little

gas, at very high price to Alaskans and

very much to Conoco’s benefit because

it would go to their refinery, and to sad-

dle Alaskans with very high energy costs

or subsidize energy costs. To the extent

that it would be subsidized would be a

very bad move. So this is a bigger line

that would result in cheaper gas for

Alaskans and it would get us export rev-

enue, and that’s important to Alaskans.

In both ways it’s superior to the small

pipeline that some of the Republicans in

the building are pushing so hard. I would

like to see this work, but it’s got warts.

Petroleum News: What are thosewarts?

Gara: One is that we want as much

natural gas development on the North

Slope as possible, the way it’s written

right now, you can expand in an eco-

nomic way through what’s called com-

pression. That is by all accounts inex-

pensive enough that

a new party can

come in and expand

the pipeline a little

bit if all that com-

pression capacity

isn’t used in an ini-

tial phase. But once

you pass the point

where you can

expand the com-

pression, and that may be 1 bcf a day,

expansion becomes prohibitively expen-

sive for one party to pay for.

We will have no development on the

North Slope at the point where the

pipeline hits its capacity with compres-

sion because an independent company

will know that it’s not worth exploring

for North Slope gas — and by the way

finding pools of oil when you find gas,

which we all believe will happen. It’s

not worth it to you to explore if you

have to pay a prohibitive cost to expand

the pipe to get your gas in the pipe.

That’s going to kill potential jobs; that’s

going to kill potential gas development;

that’s going to kill oil finds that we

need; and it’s going to kill potential

export revenue for the state. There are

only two ways around that and we’ve

received no commitment from the

administration yet.

One way is for all parties to the

pipeline to share in the cost of the

expansion. As a sovereign, it’s our inter-

est in having as much natural gas in that

pipeline; as much natural gas and oil

exploration on the North Slope as possi-

ble. The way the contract is written right

now, if an expansion reduces the cost of

shipping, Exxon, Conoco and BP get the

benefit of the reduced cost of shipping.

If an expansion raises the cost of ship-

ping, then only the state pays — and the

new party. There is an imbalance there.

The companies can’t have it both ways.

As long as the cost of the expansion

doesn’t raise any parties’ transportation

cost above what they were then the

pipeline started, then all parties should

share in it to make it feasible for the new

party to get their additional gas in. It

benefits the state, gets us new jobs, gets

us new gas revenue, and potentially gets

us new oil. As a sovereign, that’s a rule

we should impose. The alternative is to

build the pipe large enough that it can be

expanded by compression to let’s say 5

bcf a day so that we know there is sub-

stantial room by compression because

expansion by compression is affordable.

What that all goes to is called basin

control. You either let the Big 3 control

the pipeline and the natural gas on the

North Slope or you let competitors in. I

think it’s time to let competitors in, but

they won’t be allowed in unless you

allow this contract to change somehow.

Petroleum News: This bill is consid-ered enabling legislation. Basically itauthorizes the governor to move forwardwith contract negotiations. Can’t this bedealt with in the contract negotiations?

Gara: Anything can be negotiated in a

contract negotiation. As a legislator, I

think you are a fool to say here, go

negotiate. We are not

going to give you any of

the important rules we

think should be in this

contract. We’ll just assume

you’ll do the right thing.

That takes away leverage the state has to

do the right thing. That makes you trust

the governor who has not, in my view,

does not have a great track record for

negotiating a contract like this.

Petroleum News: Is the administra-tion equipped to negotiate a contractlike this? This was something identifiedduring the Murkowski administration’sefforts.

Gara: They are going to be out-

manned during the negotiations. They

are going to be leveraged during the

negotiations. The oil companies will

play their nuclear option and say look

we are not going to release any gas if

you don’t give us the terms that we need

and we need their gas for the pipeline.

They have all of the leverage in the

world during the negotiation. Right now

the Legislature has all the leverage in the

world in putting in terms to protect the

people of the state of Alaska. If we don’t

put the terms in to protect the people of

the state, and say let’s just have the gov-

ernor negotiate with three of the biggest

corporations in the world and hope he

does a good job, then I think we are less

likely to get a good outcome.

There are three or four areas that are

very important where the governor is

saying trust me I’m negotiating with the

biggest oil companies in the world even

though they have all of the leverage, and

I’ll come back with something for you.

If we do that and if the contract is bad,

we’ll be told you can’t touch the contract

and all the parties will walk away.

You’re sort of being leveraged into vot-

ing yes for it. If you set the rules up

front that are fair to everybody, where

the state doesn’t carry all the risk and in

so many provisions the state is carrying

more risk than anybody.

Petroleum News: So what are thoseareas you noted?

Gara: One is to prevent basin control,

so that independent companies know

they can get the gas into the pipeline and

it doesn’t just become Exxon, Conoco

and BP’s gas pipeline for the rest of eter-

nity. Right now it’s tilted toward them.

Another is a rule that’s

explicit in the statute that

says if the state needs addi-

tional natural gas for in-

state use we can get it for a

reasonable cost. I don’t

want to have to go to court and sue the

oil companies for them to develop natu-

ral gas by lawsuit. I want an agreement

that says as long as we pay a reasonable

cost for it, we can get it as long as there

is an in-state need so we don’t ship LNG

north to Alaska while we have the

reserves here.

Right now in a normal business rela-

tionship, all the parties go ahead and if it

fails, they all pay their share of the lost

costs. This business relationship says if

we go ahead for two, three or four years

and one of the parties backs out and it

doesn’t go ahead, we pay our costs and

we, the state of Alaska, is responsible for

Trans Canada’s cost. That puts risk on

the state and none of the other parties to

subsidize TransCanada. In any normal

business relationship, you enter into it

knowing that if it fails you pay the costs

of the investment. Here only the state —

not Exxon, not BP and not Conoco —

are kicking in to pay TransCanada so

TransCanada doesn’t pay anything for

this. That’s a tilted relationship.

We assume TransCanada leveraged

the state because it has potential legal

claims under AGIA, but the administra-

tion has refused to discuss any of those

in any meaningful way with the commit-

tee.

We are also taking a huge risk by

making this a pipeline that results in no

tax payments to the state. We can either

l G O V E R N M E N T

Gara concerned about contract outcomeAnchorage Democrat likes Alaska LNG project over in-state line; wants more instructions on negotiations in enabling legislation

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for the future of our community.”

Douglas Channel Watch, a local envi-

ronmental group which led the opposition

in the Northern Gateway vote, said the risk

from either a tanker accident or pipeline

rupture was too high a price for the small

number of jobs the project would bring to

the area, which has been on a resource-

driven rollercoaster for years.

Celine Trojand, a spokeswoman for the

Dogwood Initiative, said the plebiscite

result should inspire demands for a

province-wide vote, but that would require

signatures from 10 percent of registered

voters in every one of 85 constituencies.

More support for LNGAlthough the Northern Gateway pro-

posal has triggered a heated debate, there is

greater support among residents and First

Nations for at least three LNG export ter-

minals in the Kitimat area.

Even without final investment deci-

sions, that prospect has seen a surge in

Kitimat house prices in the first three

months of this year, with values soaring to

an average C$289,000, up 71 percent from

C$169,000 a year earlier.

Haisla Nation Chief Ellis Ross said the

Northern Gateway vote is unlikely to have

more than a symbolic impact, while Art

Sterritt, executive director of Coastal First

Nations, said the result makes no difference

to the entrenched opposition of his com-

munity.

Sterritt said Jim Prentice, a former fed-

eral cabinet minister who has been hired by

Enbridge in an effort to win over critics,

has been discussing the possibility of an

even larger aboriginal stake in the pipeline.

Jim Hatcher, a spokesman for Prentice,

would not disclose details of what has been

discussed beyond saying Enbridge has not

shifted from its original 10 percent offer

that is valued at C$280 million over 30

years.

In its latest testimony, Enbridge has

claimed to have the support of 11 of 27

British Columbia First Nations who occu-

py land within 50 miles of the pipeline

right-of-way. l

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He said it has been his choice to

“make this somewhat personal. I think

people appreciate a personal face, a per-

sonal approach to the issues. And we’ve

tried to build the trust and confidence

along with the personal approach.”

But the resistance shows no signs of

weakening, with hundreds of activists

staging a protest in the Burnaby area on

April 12 against the pipeline and its

plans to export oil sands bitumen.

However, Anderson is hopeful that

the public appreciates Kinder Morgan’s

“openness and honesty about issues”

and its candor that accidents can happen

involving pipeline spills or tankers in

open oceans.

“When you talk about risk, you are

talking probability and consequence,”

he said. “The probability of a major

incident is very, very low.”

The introduction of another 350

tankers a year into the densely populat-

ed Vancouver area will involve exten-

sive study, research and evidence to

deal with fears that risks cannot be man-

aged, Anderson said.

He said the pipeline expansion is all

about market demand and responding to

growing production in the oil sands that

has generated shipping commitments

from 13 customers for 20-year periods.

Although Asia, especially China, is

the ultimate prize, Anderson noted that

80 percent of the tankers currently leav-

ing Burnaby are destined for California

and “that’s still a market producers want

to get to simply because Alaska North

Slope crude continues to be in decline.”

In making an economic case for the

pipeline expansion in British Columbia

— despite the obvious benefits to

Alberta from oil sands royalties and

jobs — he said municipal property

taxes from the project would almost

double to more than C$40 million a

year.

As well, about two-thirds of the cap-

ital cost would be spent in British

Columbia, creating contracting oppor-

tunities, he said.

—GARY PARK

continued from page 4

NORTHERN GATEWAY

continued from page 4

KINDER MORGAN

EXPLORATION & PRODUCTIONBP continuing to evaluate heavy oil

BP is continuing an engineering analysis as part of an evaluation of the eventual

possibility of producing heavy oil from Alaska’s North Slope, Frank Paskvan, the

company’s Alaska technology manager, told the Alaska Senate Resource committee

on April 9 in answer to a question about the North Slope’s heavy oil resources.

Between April 2011 and July 2013 the company experimented with the produc-

tion of heavy oil from the Ugnu formation, a relatively shallow heavy oil reservoir

rock unit, using a $100 million test facility on S-pad in the Milne Point field.

Those tests demonstrated technical and economic challenges for heavy oil devel-

opment, Paskvan said.

Heavy oil has a thick, syrupy consistency and is too viscous for unaided trans-

portation through an oil pipeline. Because of its high viscosity, the material is very

challenging, and potentially expensive, to extract from a reservoir rock. And, to add

to the economic challenges, this type of oil has less market value than conventional

light oil.

But with an estimated 12 billion to 18 billion barrels of heavy oil lying undevel-

oped under the North Slope, this resource could perhaps help turn around the decline

in North Slope oil production.

CHOPS techniqueBP used a technique called cold heavy oil production with sand, or CHOPS, for

its heavy oil production tests. The technique involves using an augur-like progressive

cavity pump near the bottom of a well, to reduce the down-hole pressure in the well,

suck oil into the well bore from the typically unconsolidated sand reservoir and send

a slurry of sand and oil up the well bore to the surface. On the surface the sand is sep-

arated from the oil in a specially designed settling tank.

Apparently the production tests were successful, with oil production reaching lev-

els as high as 500 barrels per day.

Unfortunately, however, the Achilles heel of the process is a rotating rod that runs

down the well from a motor at the surface to drive the pump rotor deep in the well.

During testing, the spinning of this rod, with metal-to-metal contact between the rod

and the well casing, and with abrasive sand in the well, rapidly wore holes in the cas-

ing, Paskvan explained. The resulting need for frequent well repairs undermined the

already fragile economics of the process.

“So we’re doing studies now on artificial lift and hope that will improve the run

life, because these workovers and tubing replacements were very expensive and

made it difficult to continue the operations of the pilot,” Paskvan said.

—ALAN BAILEY

Although the Northern Gatewayproposal has triggered a heateddebate, there is greater support

among residents and First Nationsfor at least three LNG exportterminals in the Kitimat area.

By KRISTEN NELSONPetroleum News

T he U.S. Energy Information

Administration says the North Sea

Brent crude oil spot price averaged $107

per barrel in March, the ninth consecutive

month it has averaged between $107 and

$112 a barrel. EIA said in its April short-

term energy outlook that Brent is project-

ed to average $105 per barrel this year and

$101 per barrel in 2015.

The West Texas Intermediate crude oil

price, which fell to an average of $95 in

January, averaged $101 per barrel in

February and March “as a result of strong

Midwestern refinery runs and the startup

of the Marketlink pipeline moving crude

from Cushing to the Gulf Coast,” the

agency said. EIA expects WTI to average

$96 per barrel in 2014 and $90 per barrel

in 2015.

The discount of WTI to Brent averaged

more than $13 per barrel from November

through January and fell to nearly $7 per

barrel in March. EIA said it expects the

discount of WTI to Brent to grow to an

average of $9 per barrel this year and $11

per barrel in 2015, “reflecting the eco-

nomics of transporting and processing the

growing production of light sweet crude

oil in U.S. and Canadian refineries.”

Henry Hub natural gas spot prices

averaged $4.90 per million Btu in March,

down $1.10 from February as the weather

warmed, EIA said. The agency expects the

Henry Hub spot price to continue to

decline in the spring and projects it will

average $4.44 per million Btu this year

and $4.11 in 2015.

Crude supply growsLiquids production from non-

Organization of the Petroleum Exporting

Countries grew by 1.3 million barrels per

day in 2013, averaging 54 million bpd,

EIA said.

The agency forecasts that production

from the United States and Canada will

grow by a combined annual average of 1.4

million bpd this year and by 1.2 million

bpd in 2015, while production in the

Former Soviet Union will rise by 160,000

bpd, led by Russia in 2014 and

Kazakhstan in 2015.

OPEC crude oil production averaged

30 million barrels in 2013, down 900,000

bpd from 2012. EIA said it is projecting

OPEC crude oil production to drop by

200,000 bpd in both 2014 and 2015, “as a

result of supply disruptions in OPEC and

cutbacks in crude oil production to

accommodate increased supplies in non-

OPEC countries.”

In the U.S., EIA expects strong crude

oil production growth, primarily in the

Bakken, Eagle Ford and Permian, contin-

uing through 2015, with U.S. production

forecast to increase from an estimated 7.4

million bpd in 2013 to 8.4 million bpd in

2014 and 9.1 million bpd in 2015.

EIA said the highest historical annual

average production level in the U.S. was

9.6 million bpd in 1970.

Bakken production averaged 900,000

bpd in 2013 and Eagle Ford production

averaged 1.1 million bpd.

Low level of natural gas storageWorking natural gas in storage ended

March at an estimated 875 billion cubic

feet, EIA said, the lowest level in 11 years.

The agency projects a large rebuild over

the injection season with inventories at the

end of October expected to be 3.422 tril-

lion cubic feet, “a record build” of nearly

2.6 tcf.

U.S. natural gas consumption is

expected to average 72.1 bcf per day this

year, up 0.7 bcf from 2013, with increased

residential, commercial and industrial use

offsetting declines from the electric power

sector related to higher natural gas prices.

EIA expects marketed natural gas pro-

duction to grow by 3 percent in 2014 and

1 percent in 2015, with rapid natural gas

production growth in the Marcellus con-

tributing to falling natural gas prices in the

Northeast which may result in some

drilling activity moving “away from the

Marcellus back to Gulf Coast plays such

as the Haynesville and Barnett, where

prices are closer to the Henry Hub spot

price.”

Liquefied natural gas imports have

been declining as higher prices in Europe

and Asia are more attractive to sellers than

relatively lower U.S. prices. EIA also said

that growing domestic production has dis-

placed some natural gas pipeline imports

from Canada while exports to Mexico

have increased.

The agency projects net imports of 3.7

bcf per day in 2014 and 3 bcf in 2015,

which would be the lowest level since

1987, and expects that beginning in 2018

the U.S. will be a net exporter of natural

gas. l

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

Henry Hub gas to average $4.44 this yearEIA says natural gas averaged $3.73 per million Btu in 2013; Brent averaged near $110 per barrel in March for 9th consecutive month

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l G O V E R N M E N T

Interior publishes mitigation strategySays new landscape-level approach to federal land management will effectively reconcile development needs with conservation

By ALAN BAILEYPetroleum News

Following a directive by Interior

Secretary Sally Jewell in October, the

Department of the Interior has published

a new strategy for the mitigation of the

environmental impacts of development

projects on federal land. Characterized as

“landscape-level” planning, the concept

is to approach mitigation on a regional

basis, looking at overall environmental

priorities and the appropriate policies for

permitting multiple projects, rather than

dealing with projects piecemeal, on a

project-by-project basis, Interior says.

“The goal is to provide greater certain-

ty for project developers when it comes to

permitting and better outcomes for con-

servation through more effective and effi-

cient project planning,” Jewell said in an

April 10 news release announcing publi-

cation of the strategy. “Through advances

in science and technology, advance plan-

ning, and collaboration with stakeholders,

we know that development and conserva-

tion can both benefit — and that’s the

win-win this mitigation strategy sets out

to achieve.”

Given that any development project

will inevitably have some environmental

impact, the concept behind environmen-

tal mitigation is to avoid some impacts

and minimize others through the appro-

priate siting and design of facilities or

infrastructure that need to be built. For

impacts that are unavoidable, the new

strategy sets a target of seeking means of

compensating for these impacts through

the protection or restoration of equivalent

environmental resources.

There are currently several means

whereby this type of environmental com-

pensation can be achieved in conjunction

with a federal permit, including the carry-

ing out of a mitigation activity by the per-

mit holder or the purchase of compensa-

tory mitigation through a mitigation

bank, Interior’s strategy document says.

The strategy document says that

Interior’s new approach will involve first

identifying landscape-scale attributes

within a region, and the characteristics of

these attributes. Based on this analysis,

Interior will develop landscape-scale

goals and strategies, thus enabling the

development of efficient and effective

compensatory programs for environmen-

tal impacts that cannot be avoided or min-

imized. Then, over time, Interior will

monitor and evaluate progress, making

adjustments to the landscape-level miti-

gation plans, as conditions change.

The environmental impacts and miti-

gation requirements of individual projects

will presumably be evaluated against the

overall mitigation strategy.

Interior has set out a series of guiding

principles under which the strategy will

be implemented. These principles include

8 PETROLEUM NEWS • WEEK OF APRIL 20, 2014

WE KNOW PIPES, INSIDE AND OUT.

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

State partly approves Oooguruk expansionAgrees expanded Nuiqsut participating area is justified but wants to see plan for more development drilling in additional acreage

By ALAN BAILEYPetroleum News

A laska’s Division of Oil and Gas has approved in

part an application by Pioneer Natural Resources to

expand the Nuiqsut participating area in the Oooguruk

oil field in the nearshore waters of the Beaufort Sea, off-

shore the North Slope. The state says that it agrees that

the requested expansion region for the participating area

includes acreage likely to be capable of contributing to

the production of hydrocarbons, but that Pioneer’s plan

of development does not commit to drilling in the entire

region. Because of this lack of sufficient drilling com-

mitment, it would not be in the state’s interest to grant

the entirety of the requested expansion, Bill Barron,

director of the Division of Oil and Gas, wrote in the divi-

sion’s approval document for the expansion.

“Therefore, under this decision, the division is

approving 800 acres of the proposed 1,040 acres, adding

an additional 120 unrequested acres, and denying the

remaining undrilled 240-acre area proposed for expan-

sion,” Barron said.

The total size of the approved expansion area is, thus,

920 acres.

Three poolsThe Oooguruk field contains three producing oil

pools. The deepest is the Nuiqsut, broadly equivalent to

the reservoir sands of the nearby Alpine field. Above the

Nuiqsut lies the Kuparuk C, equivalent to one of the pro-

ducing sands in the Kuparuk River field. The shallowest

pool, in the Torok formation, is equivalent to the reser-

voir of the Nanuq satellite field at Alpine.

A participating area, somewhat equivalent to an oil or

gas reservoir, defines an area within which hydrocarbon

production takes place under the defined structure of the

participating ownership interests of an oil and gas unit.

The Oooguruk field went into production in June

2008 from an artificially constructed gravel island.

Initial development focused on the Nuiqsut and the

Kuparuk, while the Torok has seen recent development

efforts in the form of a project called “Nuna.” The state

previously approved a 2,400-acre expansion of the

Nuiqsut participating area in May 2013.

The state’s new participating area expansion approval

document says that Pioneer has been able to optimize its

well designs to extend the reach of the drilling from the

Oooguruk island to more distant parts of the Nuiqsut

reservoir, thus driving a need for a larger participating

area. This most recent expansion is to the southwest of

the existing participating area, the document says.

As in the Alpine field, the Nuiqsut reservoir tends to

consist of relatively fine-grained sediments that tend to

inhibit the flow of oil towards production wells. But with

the oil in the Nuiqsut being thicker and heavier than in

Alpine, Pioneer has had to try a variety of development

techniques to boost production rates to acceptable levels.

Those techniques have included the injection of a mix-

ture of glycol and water for enhanced oil recovery, the

use of horizontal wells and the use of multi-stage

hydraulic fracturing. l

see MITIGATION STRATEGY page 9

By GARY PARKFor Petroleum News

AFirst Nations’ company, backed by

one of British Columbia’s wealthi-

est families, is trying to seize the initia-

tive in moving synthetic crude rather

than controversial bitumen from the

Alberta oil sands to the Pacific Coast by

proposing an alternative to Enbridge’s

floundering Northern Gateway project.

Only two days after the residents of

Kitimat registered clear-cut opposition

to Northern Gateway in a community

plebiscite, the alternative scheme sur-

faced.

Eagle Spirit Energy Holdings, formed

two years ago to promote a First Nations

energy corridor across northern British

Columbia, unveiled its plan and dis-

closed that the Vancouver-based

Aquilini Group, a powerhouse developer

whose principal investors own the

Vancouver Canucks of the National

Hockey League, was ready to underwrite

the cost of the pipeline.

The C$18 billion venture has set a

tentative startup date of 2020 to deliver

1 million barrels per day of oil sands

bitumen to Prince Rupert along with nat-

ural gas to serve local communities and

as feedstock for LNG projects, a fiber

optic cable, electrical and water lines.

Backing claimed, dismissedThe announcement April 14 was

joined by about 20 British Columbia

First Nations chiefs, with the promoters

claiming to have the backing of most

First Nations along the right of way,

although some aboriginal leaders were

quick to dismiss the idea.

Eagle Spirit Chairman and President

Calvin Helin said the proposal has First

Nations’ backing because it would be

largely Native controlled and would be

routed to Prince Rupert rather than

Kitimat.

He said some of the aboriginal sup-

port comes from communities that have

been “staunchly opposed” to Northern

Gateway, but non-disclosure agreements

prevent him from naming the First

Nations other than the 150 members of

Nee Tahi Buhn, which has withdrawn its

endorsement of the Enbridge pipeline.

Enbridge has long claimed it has 26

equity partnerships in place with First

Nations and Metis communities for

Northern Gateway representing about 60

percent of the native population along

the proposed route.

An Enbridge spokesman said the

company has not received notification

that any of the aboriginal partners have

withdrawn, or been told that non-disclo-

sure agreements have been cancelled.

Aquilini says it has customers lined up

Aquilini President David Negrin told

reporters his company decided 18

months ago to back Eagle Spirit and has

customers “lined up,” using its leverage

from business dealings with China.

Helin said the Eagle Spirit energy

corridor would be located away from the

congested and “torturous” routes that

have undermined the connection to

Kitimat.

In addition, First Nations “do not

believe Kitimat is an appropriate termi-

nus because it exposes the coastline to

too much risk,” he said.

The proposal will be further strength-

ened by converting oil sands bitumen to

synthetic crude by refining the output at

an upgrader that First Nations are open

to building in eastern British Columbia

to gain some of the key economic bene-

fits associated with producing and refin-

ing bitumen, Helin said.

“Money and technical expertise is not

going to be a problem,” he said. “It is

very clear what the problem is: First

Nations’ social license.”

CERI says this may be ‘road ahead’Peter Howard, chief executive officer

of the Canadian Energy Research

Institute, said Eagle Spirit may have

found a “road ahead” if it is able to

assure First Nations of financial com-

pensation and active participation in the

project.

David Collyer, president of the

Canadian Association of Petroleum

Producers, told the Calgary Herald that

the Eagle Spirit proposal could offer a

“way through” the current impasse with

Northern Gateway.

For producers, the objective is to get

bitumen to the British Columbia coast

and Asia, so “the more options the bet-

ter.”

Chief Archie Patrick of the Stellat’en

First Nation said in a statement that

“everyone knows oil is coming through

British Columbia at some point. There is

a cost to doing nothing. We do not want

someone else to determine our future.”

Matt Horne, a British Columbia exec-

utive with the Pembina Institute, said

Eagle Spirit is pitching an idea that

“seems similar” to a C$26 billion plan

by media owner David Black to refine

oil sands crude at Kitimat, to reduce the

dangers of a bitumen spill in open water.

He said the Black idea has attracted a

“lot of skepticism around its economics”

and Eagle Spirit may face the same

doubts.

Black has conceded that oil sands

producers are unwilling to participate in

his project, preferring instead to sell

their raw bitumen outside North

America.

Art Sterritt, executive director of the

Coastal First Nations, representing eight

aboriginal communities, doubted Eagle

Spirit’s claims of Native backing, noting

that only two small First Nations sent

representatives to the Vancouver news

conference. l

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

Northern Gateway faces rivalFirst Nations, BC industrial giant unveil plans for C$18B energy corridor to BC coast in bid to attract aboriginal participation

PETROLEUM NEWS • WEEK OF APRIL 20, 2014 9

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For nearly a century Foss has successfully navigated Alaska’s most extreme environments.

the establishment of protocols that will

simplify planning and improve opera-

tional certainty for development projects;

the incorporation of mitigation planning

into the early stages of project planning;

the use of scientific information and

tools; promoting mitigation efforts that

improve the resilience of U.S. resources

under a changing climate; transparency

and consistency in the development of

mitigation measures; collaboration

between federal agencies and with state

agencies, tribes and other stakeholders;

and the monitoring and evaluation of mit-

igation results.

Initiatives already under way, such as

the implementation of a new tool for

assessing wildlife critical habitat in 16

western states, will dovetail into the new

strategy, helping projects during pre-

planning and reducing surprises, con-

flicts and costs as projects progress,

Interior says. l

continued from page 8

MITIGATION STRATEGY

Art Sterritt, executive director ofthe Coastal First Nations,

representing eight aboriginalcommunities, doubted Eagle

Spirit’s claims of Native backing,noting that only two small First

Nations sent representatives to theVancouver news conference.

By WESLEY LOYFor Petroleum News

A lyeska Pipeline Service Co. is ques-

tioning the need for extensive “cor-

rective measures” federal regulators are

proposing for the trans-Alaska oil

pipeline.

Alyeska is the Anchorage-based com-

pany that runs the 800-mile pipeline on

behalf of owners including BP,

ConocoPhillips and ExxonMobil.

The U.S. Pipeline and Hazardous

Materials Safety Administration recently

issued Alyeska a “notice of proposed

safety order” with a list of corrective

actions to address an unusual event along

the pipeline.

The event involved the Sept. 8, 2013,

discovery of a stray piece of metal lodged

inside a valve at the Valdez Marine

Terminal at the end of the pipeline.

Alyeska was able to trace the piece to

a failed maintenance job in August 2012

near milepost 385, about 70 miles

pipeline north of Fairbanks.

The job involved welding a domelike

“encapsulation” over an unused pipeline

air vent, and filling it with epoxy. The

encapsulation was welded onto the

pipeline at the 12 o’clock position.

The problem was that as the epoxy

cured, incredible pressure built up inside

the encapsulation — enough to punch out

the pipeline wall underneath.

The round piece, 10 inches in diameter

with a stem attached, felt into the pipeline

and rode in the oil stream to Valdez.

Concerns about other capsAlyeska workers simply didn’t antici-

pate the punch-out at MP 385, Alyeska

spokeswoman Michelle Egan told

Petroleum News.

The federal pipeline regulators have

raised concerns that similar problems

might be lurking at some 90 other epoxy-

filled encapsulations Alyeska installed

over pipeline vents and drains between

2010 and 2013.

The purpose of the encapsulations was

to safeguard against potential spills.

PHMSA, in its notice, proposed sever-

al corrective measures and deadlines,

including increased encapsulation moni-

toring, ultrasonic and other testing, and

pressure relief.

Alyeska has said it’s operating the

pipeline with “full confidence” in its

integrity.

In an April 11 letter responding to

PHMSA, Alyeska said pipeline pigging

and radiographic exams showed that no

other encapsulations have metal loss.

Alyeska took immediate steps to repair

the failed vent encapsulation at MP 385,

and “has taken numerous investigative

and corrective actions in response to the

incident,” said the letter, signed by com-

pany President Tom Barrett.

The letter said Alyeska “has questions

about the justification and scope of cer-

tain of the proposed corrective measures

and the potential magnitude of actions

that would be necessary to implement the

corrective measures as proposed, and

within the apparent expected time-

frames.”

Expert contractor retainedAlyeska requested “informal consulta-

tion” with PHMSA, which was one of the

response options available to the compa-

ny under the proposed safety order.

This likely will involve a sit-down

between Alyeska and PHMSA regulators,

possibly at the agency’s Denver office on

May 8.

In its letter, Alyeska said work to fur-

ther address concerns raised in the pro-

posed safety order is planned for the

upcoming summer along the pipeline,

which is partly buried and partly above

ground.

“Alyeska is conducting engineering

design for the construction packages

needed for the 2014 encapsulation

inspection digs,” the letter said.

The company has contracted with

Stress Engineering Services for “techni-

cal lab testing and analysis relating to

epoxy and structural questions,” the letter

said. “They have begun their analysis and

we expect their work to help inform deci-

sions on any further encapsulation work

and/or monitoring. The final scope of

work includes the rigorous testing

designed to answer the concerns outlined

in the proposed safety order.”

In light of the work the contractor is

doing, Alyeska said it “requests further

discussions concerning PHMSA’s

assumptions and expectations as to neces-

sity, scope and schedule” for a proposed

requirement to test pressure inside the

encapsulations, and relieve pressure if

necessary. l

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

Alyeska questions ‘stray metal’ listFederal regulators propose several ‘corrective measures’ to prevent another wall failure along 800-mile trans-Alaska pipeline

10 PETROLEUM NEWS • WEEK OF APRIL 20, 2014

ComplianceSystems

SafetyPersonnel

ProfessionalServices

907.743.9871TotalSafety.com

Total Solutions:rea A Systems

G Detec Systems

2Safet Consultants

Safet M TrainingRemot rgenc M rt

T Safet r rointegrat fety c ct r fet workersassets, environment.

FINANCE & ECONOMYBill Richardson elected to Miller board

Miller Energy Resources Inc. has added Bill Richardson, former New Mexico gov-

ernor and U.S. energy secretary under President Clinton, to its board of directors.

Richardson was among eight directors elected to one-year terms at Miller’s April

16 annual shareholders meeting.

Miller, based in Knoxville, Tenn., operates oil and gas properties in Alaska through

its subsidiary, Cook Inlet Energy LLC.

Miller shares are listed on the New York Stock Exchange.

“We are a stronger company than we have ever been and we expect fiscal 2015 will

see continued value creation,” said Scott M. Boruff, Miller chief executive and him-

self a board member. “We believe all the necessary pieces are in place: access to favor-

able financing, promising drilling targets, greater wellbore diversification, and a

favorable Alaskan tax environment.”

—WESLEY LOY

The encapsulation that was welded over a vent on the pipeline near milepost 385, north ofFairbanks.

ALY

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IPEL

INE

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ICE

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.

By KRISTEN NELSONPetroleum News

Construction of a natural gas pipeline from the North

Slope and a liquefied natural gas facility at Nikiski

will impact state infrastructure, particularly roads and

bridges. Language in the Alaska LNG Project heads of

agreement between the state, the Alaska Gasline

Development Corp., TransCanada, ExxonMobil,

ConocoPhillips and BP calls for the state to provide sup-

port in a number of ways, including “Appropriations and

permitting for the construction of necessary in-state infra-

structure (e.g., roads, bridges), including drafting, intro-

ducing and supporting legislation,” language which has

some legislators concerned.

Members of the House Finance Committee expressed

concern in mid-April hearings that the HOA language

was requiring the state to pick up infrastructure needed

for the project without participation by other partners in

the project.

Joe Balash, commissioner designee of the Department

of Natural Resources, told the committee April 15 that the

language cited in article 10 of the HOA was “in many

respects ministerial.” He said the article 10 language

needs to be read in conjunction with article 9, which pro-

vides for establishment of impact payments to be made

by parties to the Alaska LNG project “to help offset

increased service and other costs borne by the state and

local governments” during project construction.

DOT’s perspectiveThe Alaska Department of Transportation and Public

Facilities told House Finance April 14 that it has been

working on infrastructure issues for gas pipelines over

the last 10 years.

Jeff Ottesen, DOT’s director of program development,

compared this project to circumstances in the state in the

1970s when the trans-Alaska oil pipeline was built. He

said the state’s population and traffic are at least triple

what they were in the 1970s and the Dalton was a private

road then whereas now it is a public highway, creating

many more miles of road where general traffic would

merge with pipeline traffic.

Safety is a concern, Ottesen said, citing 50 highway

fatalities in 1973, prior to pipeline construction, com-

pared to 137 in 1977, “so clearly the pipeline activity in

the ’70s had an impact on public safety.”

There were just 50 fatalities last year, Ottesen said,

and the department doesn’t want to see that number

increase.

Another big difference today is use of modules, large

prefabricated elements, often as wide as 20 feet and up to

20 feet high, weighing up to 400,000 pounds.

Such modules now move regularly between Cook

Inlet and the North Slope and Ottesen said the expecta-

tion is that the number of modules would “go up quite

dramatically,” requiring places for modules to get off the

highway to allow general traffic to get around what is

basically “a rolling traffic jam” often traveling at 5 to 10

mph in a very large configuration.

A third difference is that the gas pipeline is expected

to be buried, requiring more earthwork and more truck-

loads on the highways, he said.

Ottesen said the department is in a good place today

because it began 10 years ago to upgrade bridges with

deficiencies and to address highway issues.

The Tanana River Bridge, just east of Tok, was

upgraded for two reasons, he said: For proposed pipeline

work and because it was “the weakest link for truck hauls

between the Lower 48 and Alaska.” Replacing that bridge

was a benefit to commerce, he said.

Work on the Parks Highway this summer will add 14

new passing lanes, he said, with another 14 scheduled to

be built by the summer of 2017, helping the conflict

between general and truck traffic on that highway.

DOT doesn’t know the logistics plan for the Alaska

LNG project, he said, but expects turning lanes and

turnouts for modules will be required, as well as airport

and port work.

While much highway work benefits from federal

funding, that isn’t true for maintenance projects such as

gravel replacement on the Dalton Highway, or for port or

railroad work. There is federal funding for airport work,

he said, but what that work can be is generally federally

proscribed and may not meet the needs of a gas project.

In general, Ottesen said, DOT has been dealing with

major transportation issues identified when a project was

proposed 10 years ago. He said the department has “got-

ten an awful lot done in the past decade.”

Who pays?On the issue of why pays for the work, Department of

Transportation and Public Utilities Commissioner Pat

Kemp told the committee that it’s the department’s role to

ensure the state’s highways “are strong enough to accom-

modate a load that can be permitted.”

“So within the right of way I believe the brunt of the

work should be on the department.”

However, the roadway and improvements to a new

intersection required by the project, “should be assigned

to the entity developing the pipeline,” Kemp said, and

compared it to work required if a large new store goes in

— road improvements required for that facility would be

paid by the store.

PETROLEUM NEWS • WEEK OF APRIL 20, 2014 11

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l N A T U R A L G A S

Legislators mull infrastructure costsLanguage in heads of agreement concerns House Finance members; DOT cites its policy for roadwork around new retail developments

Ottesen said the department is in a good placetoday because it began 10 years ago to

upgrade bridges with deficiencies and toaddress highway issues.

see INFRASTRUCTURE COSTS page 13

By ERIC LIDJIFor Petroleum News

Buccaneer Alaska Operation LLC is

seeking an incidental harassment

authorization for a proposed multiwell

offshore exploration program in Cook

Inlet starting this summer.

The local subsidiary of Australian

independent Buccaneer Energy Ltd. is

asking the National Marine Fisheries

Service for the authorization, which

allows a company to unintentionally

harass some marine animals during the

course of certain activities. The authori-

zation includes a legal definition of

“harassment” ranging from annoyance to

injury. The authorization is required for

most offshore exploration in the Cook

Inlet.

The federal agency is taking com-

ments on the request through May 7.

Buccaneer originally proposed a six-

well program when it initially applied for

the authorization in August 2013, but sub-

sequently reduced the scope to a four-

well program.

The current authorization would only

cover 2014 component of a multiyear

program.

Buccaneer is proposing to drill as

many as two wells during the open water

season, which runs from April 15 to Oct.

31, but is occasionally extended when

weather permits. It expects each well to

take 30 to 75 days to drill with another

seven to 15 days of testing.

The potential sources of harassment

being considered include: towing the

Endeavour jack-up rig to well sites, driv-

ing conductor pipe, drilling the explo-

ration wells, conducting vertical seismic

profiling in the wellbore and conducting

helicopter logistics.

Those activities could disturb a range

of seas creatures. “The marine mammal

species that is likely to be encountered

most widely (in space and time) through-

out the period of the planned surveys is

the harbor seal,” the federal agency wrote

in a public notice.

Other sea creatures in the region

include the federally protected beluga

whale and stellar sea lion, but Buccaneer

is not requesting permission to incidental-

ly harass either species.

The federal agency, though, is consid-

ering the impact of the exploration work

on killer whales, harbor porpoises, gray

whales, minke whales, dall’s porpoises

and harbor seals.

Tyonek Deep, Southern CrossThe Buccaneer application includes

four potential well locations for this com-

ing year: the Tyonek Deep No. 1 and

Tyonek Deep No. 2 wells at the North

Cook Inlet unit, and the Southern Cross

No. 1 and Southern Cross No. 2 wells at

the former Southern Cross unit.

ConocoPhillips operates the North

Cook Inlet unit, but farmed-out the deep

oil rights at the legacy gas field to

Buccaneer. Buccaneer previously operat-

ed the Southern Cross unit, but relin-

quished the unit earlier this year after fail-

ing to meet work commitments required

to cure a previous default that came from

missing previous work commitments.

While many of the Southern Cross

leases consequently expired, Buccaneer

subsequently transferred its working

interest in two Southern Cross leases to

Hilcorp Alaska LLC. One lease remains

active until September and the other

rejoined an older “parent lease.”

The application describes the Tyonek

Deep wells as the “priority” for this year,

but also said that all four well locations

are being considered “to allow for opera-

tional flexibility.” l

12 PETROLEUM NEWS • WEEK OF APRIL 20, 2014

Flint Hills Resources AlaskaJenner & Block LLPKoniag Inc.Northern Economics Inc.Pacific Star EnergyStoel Rives LLPTrident Seafoods CorporationUdelhoven Oilfield System Services Inc.

Lead Corporate Partners ($25,000 & above)Alaska Airlines & Horizon Air. . Alaska Journal of CommerceBP . ConocoPhillips Alaska, Inc. . Petroleum News

Corporate PartnersABR Inc.Alaska Business MonthlyAlaska Journal of CommerceAlaska Rubber & Supply Inc.Alaska Wildland AdventuresBear Track InnBooz Allen HamiltonBristol Bay Native Corporation

Calista CorporationCarlile Transportation Systems Inc.CIRIClark James Mishler PhotographyCONAM Construction CompanyCopper Whale InnDenali National Park Wilderness Centers Ltd.Fairweather LLC

Thank You

The mission of The Nature Conservancy is to conserve the lands and waters on which all life depends.

715 L Street . Suite 100 . Anchorage, AK 99501 . alaska@tnc.org . 907-276-3133 . nature.org/alaska

Corporate Council on the Environment

The Nature Conservancy is proud to collaborate with a wide range of partners to ensure Alaska’s lands and waters continue to support abundant

salmon and wildlife populations. We thank these corporations for sharing our vision of a healthy and productive Alaska for many generations to come.

CA

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OTO

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M

NATURAL GASDEC proposes Furie onshore facility approval

The Alaska Department of Environmental Conservation has proposed toapprove an owner requested air emissions limit for Furie Operating Alaska’splanned natural gas processing facility on Alaska’s Kenai Peninsula. The approvalwould enable the plant to operate without an air emissions permit, provided thatemissions from the plant remain below certain specified limits. The emissions thatFurie has specified for the plant from gas compressors, an auxiliary generator anda gas flare fall below the threshold at which the need for a minor air permit kicksin, the department says.

The department requires comments on the proposed approval by May 12.Furie has said that between April and October this year it plans to install an off-

shore gas production platform in its Cook Inlet Kitchen Light unit, together witha gas pipeline system to shore and an onshore gas processing facility that willdeliver natural gas into the Kenai Peninsula gas pipeline infrastructure.

The onshore facility will be located on a 10-acre site near the Cook Inlet GasGathering System East Forelands production facility. Twin gas-gatheringpipelines will run on the seafloor from the offshore platform. The pipelines willpass underground, from a point outside the intertidal zone, to run under a coastalbluff and emerge at Furie’s onshore facility.

The offshore platform will produce gas from a field that Furie has discoveredin its Kitchen Lights unit. Furie’s plan of operations for the field says that thecompany anticipates production of up to 30 billion cubic feet of gas per year, witheach of the twin pipelines initially transporting up to 100 million cubic feet perday of gas.

—ALAN BAILEY

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

Feds consideringBuccaneer IHABuccaneer requesting incidental harassment authorization forproposed offshore exploration in the upper Cook Inlet this year

By KRISTEN NELSONPetroleum News

BP Exploration (Alaska) has

announced $76 million in work for

three turnarounds planned for Prudhoe

Bay this summer, including a module for

Gathering Center 2 completed at NANA’s

Big Lake facility in April. Turnarounds

are an opportunity for scheduled mainte-

nance typically tied in with scheduled

maintenance downtime on the trans-

Alaska oil pipeline.

A BP presentation to Senate Resources

listed major facility investments commit-

ted to safe and sustainable operations,

including the $76 million in turnarounds

involving more than 700 people and

including the GC2 module.

The $13.5 million GC2 truckable

module is a debottlenecking module that

will improve gas handling capacity of an

existing low pressure separator module at

GC2, said information provided by BP

Alaska spokeswoman Dawn Patience in

an email.

This debottlenecking project will be

installed during summer turnarounds at

Prudhoe Bay, and will add some 2,000

barrels per day of oil production. The

module is a pressure safety valve relief

system.

The BP statement said the company

continues to look for opportunities to

optimize production through improving

operations efficiencies and planned main-

tenance. Debottlenecking projects fall

into three categories, the company said:

debottlenecking process fluid changes

(more water is now produced from

Prudhoe Bay and less oil); pipeline work;

and secondary recovery through

improved water management.

Summer turnaroundsBP has three turnarounds scheduled

for Prudhoe Bay facilities this summer,

the company said, including the Central

Gas Facility, GC2 and Flow Station 3,

with work focused on facility mainte-

nance, vessel repairs and other improve-

ment projects. For eight to 10 weeks,

BP’s workforce on the North Slope will

grow by nearly 700 people, the company

said.

The GC2 turnaround activity includes

module installation; installation of elec-

tric panels and wiring; installation of tie-

in spools; setting of the new module; and

final connection.

Compressor skidsIn addition to scheduled turnaround

work, BP is also doing a $290 million

compressor replacement project at the

three Flow Stations on the eastern area of

Prudhoe Bay, with the project skids also

being constructed at the NANA Big Lake

Facility.

This project is in the North Slope con-

struction phase and some of the work will

take place at the same time as the turn-

arounds to take advantage of planned

plant and pipeline shutdowns.

This work will replace the gas com-

pressors at the three Flow Stations with

state-of-the-art centrifugal compressors

driven by electric motors and will also

include upgrades to some of the auxiliary

equipment associated with the compres-

sor train.

BP said more than 15 Alaska-based

companies are involved: NANA

Development Corp., NANA

WorleyParsons, CH2MHill, ASRC,

NANA Construction, Norcon,

Udelhoven, CCI, Bell & Associates,

Glacier Services, Safeway, Carlile, Peak,

AE Solutions, GCI and Alaska Roteq.

Road work also plannedIn other North Slope work planned for

this summer season, BP has applied to the

Alaska Department of Natural Resources

Division of Oil and Gas for authorization

to increase the crown width of the Spine,

East Dock, West Dock and W Pad Access

roads in the Prudhoe Bay unit. The

increased crown width of the roads would

facilitate access for drilling rigs, rig

camps and heavy equipment. BP said in

its project description that rigs used for

existing well work are larger than the

ones used when the roads were construct-

ed. Work would be done from June to

October.

Spine Road would be expanded from

M Pad to Frontier Pad; West Dock Road

from Flow Station 1 to East Checkpoint;

East Dock Road from MCC to DS4; and

the W Pad access road from Spine Road

to W Pad.

BP said gravel, from the Put 23 Mine

Site, will be spread by equipment work-

ing on the existing roads, so tundra travel

will not be necessary. l

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

BP works ahead for summer turnaroundsCompany has work scheduled this year at 3 Prudhoe Bay facilities: Central Gas Facility, Gathering Center 2 and Flow Station 3

PETROLEUM NEWS • WEEK OF APRIL 20, 2014 13

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Where the road ends…

Our Work BeginsHe said he believes passing lanes would

fall to the department, while pull offs for

modules “should probably be on the devel-

oper.”

Balash told the committee April 15 that

the administration’s expectation is this is

going to work like any other commercial

entity approaching DOT for infrastructure

with the commercial entity providing funds

for things like turn lanes.

Balash said “the project will pay for

those things that are attributable solely to

the project” and where usage will be mixed

“our expectation is DOT will be ... calling

the balls and strikes on what things are 100

percent project and what things are partial-

ly attributable to the project.”

Deputy Commissioner of Revenue

Mike Pawlowski noted that the HOA rec-

ognizes the need for impact payments to

offset project impacts and said “develop-

ment of an impact-payment schedule is part

of the negotiations to be determined.” l

continued from page 11

INFRASTRUCTURE COSTS

NANA Development Corp. worker Justin Peterson with Prudhoe Bay GC2 module under con-struction at the NANA Big Lake facility.

Kara Dunphy, BP lead project engineer, andFred Elvsaas, NANA Development projectmanager, with the GC2 module.

PHO

TOS

CO

URT

ESY

BP

14 PETROLEUM NEWS • WEEK OF APRIL 20, 2014

EXPLORATION & PRODUCTIONIs North Slope shale oil really feasible?

The question of why major oil companies do not appear to have shown any

interest in potential North Slope shale-oil development came up at a meeting of the

Commonwealth North Energy Action Coalition on April 11. The development of

new oil resources from “tight” shale formations has upended the U.S. oil industry

in the Lower 48. So, why not tackle the North Slope oil source rocks using the

same approach as is being used in states such as Texas and North Dakota?

Scott Jepsen, ConocoPhillips vice president of external affairs, told the meeting

that his company views this type of development in Alaska as very challenging.

“Our assessment is that it’s not quite the same rock as you have down in those

places and the economics are pretty tough for shale oil up here,” he said.

Jepsen said that the initial decline rate for a shale-oil well is generally very high,

making the economics in Alaska for shale very different from elsewhere. In North

Dakota and Texas a typical development involves a well at every lease-line inter-

section, he said.

“They’ve got roads and pads everywhere. You can’t do that here,” he said.

—ALAN BAILEY

Legislature approves AGDC board changeFollowing approval by the Alaska House April 9, House Bill 383, allowing the

governor to appoint a non-state resident to the board of the Alaska Gasline

Development Corp., passed the Senate April 15 and was sent to the governor for

his signature.

The bill is essentially a fix for HB 4, passed last year, expanding the power of

AGDC to work on an in-state gas pipeline. House Speaker Mike Chenault, R-

Nikiski, and Rep. Mike Hawker, R-Anchorage, cosponsors of HB 4, said it was

always their intent that HB 4 allowed the governor the widest latitude in selecting

qualified individuals to serve on the board, including nonresidents.

The Alaska Constitution requires appointments to the U.S. citizens; HB 383

exempts public members of the board from a state statute which requires state res-

idency. As amended in House Rules, it also requires the governor to explain to the

Legislature in writing the reasons for appointment of a nonresident. The bill is

retroactive to Sept. 1.

The governor appointed one non-state resident, Richard Rabinow, and that

nomination drew fire because he is not a resident. The governor’s appointments

were up for legislative approval as this issue of Petroleum News went to press.

—KRISTEN NELSON

GOVERNMENT

l N A T U R A L G A S

House Financeplanning to amendSenate Bill 138Governor’s enabling legislation for state participation in an AlaskaLNG project in last House committee as Legislature winds down

By KRISTEN NELSONPetroleum News

As Petroleum News went to press

Senate Bill 138, the governor’s

enabling legislation for state equity par-

ticipation in an Alaska LNG project, was

in the amendment process in its last com-

mittee, House Finance. The committee

received numerous briefings on the heads

of agreement and the memorandum of

understanding before receiving the bill

from House Resources April 11. The

Legislature is set to gavel out April 20.

House Finance members have

expressed concerns over a number of

issues, some raised by consultant Roger

Marks, and some raised by the

Legislature’s main consultants on the bill,

Nikos Tsafos and Janak Mayer of enalyt-

ica.

Step by step or all in advanceTsafos and Mayer highlighted what

they see as the Legislature’s major deci-

sion in testimony April 11 and April 15.

On April 11 Mayer said that at a high-

level overview much of the discussion

comes down to commitments the state is

making now and those it makes in the

future — and how much it should try to

nail down now and how much it should

negotiate in the future.

The administration has described the

process under the heads of agreement

(signed by the commissioners of Natural

Resources and Revenue, the Alaska

Gasline Development Corp., BP,

ConocoPhillips, ExxonMobil and

TransCanada) and the memorandum of

understanding (between the state and

TransCanada), a process which is enabled

in SB 138, as a step-by-step procedure,

with the first step allowing the state to

engage in pre-FEED (front-end engineer-

ing and design) work for an Alaska lique-

fied natural gas project.

Negotiations would result in long-term

agreements requiring legislative approval

and legislators would be consulted under

confidentiality agreements as talks

progress.

Mayer said from a legislative perspec-

tive it is difficult to think about decisions

in the future, but he said the decision fac-

ing legislators was whether to approve an

initial framework with partners commit-

ting to work together to go forward or

laying it all out in advance, as was done

under the Stranded Gas Development

Act, before money is spent refining the

project.

Marks says get in after sanctionMarks told the committee April 11 that

he views the big questions before legisla-

tors as should the state get into the project

before the project is sanctioned — the

final investment decision; financing

options other than through TransCanada;

and whether the Alaska Gasline

Inducement Act project can be declared

uneconomic giving the state freedom to

go forward without TransCanada, which

holds the AGIA license. The MOU transi-

tions the state and TransCanada out of

AGIA and into a more traditional com-

mercial arrangement under which

TransCanada would put up money for the

state’s share of the North Slope gas treat-

ment plant and the pipeline, which the

state would repay through a transporta-

tion tariff once gas begins to flow.

By delaying state participation until

the project is sanctioned the state would

eliminate the risk of spending money

developing a project which doesn’t get

built, he said.

Marks also said he thought the state

taking its gas in kind rather than in value

Tsafos said whether legislatorspass the legislation or chose a

different path, the most difficultthing about LNG is that

everything has to take place inparallel, not in sequence.

see SB 138 UPDATE page 15

By WESLEY LOYFor Petroleum News

Abill to hike an environmental sur-

charge on oil production appeared

dead as the Alaska Legislature lumbered

toward adjournment.

The legislation, House Bill 325,

remained in the House Resources

Committee on April 16, four days before

lawmakers were scheduled to gavel out

for the year.

State Rep. Cathy Munoz, R-Juneau,

the bill’s prime sponsor, introduced the

bill on Feb. 21 and said it was “intended

to help start a discussion on how best to

protect the public good of having funds

available to prevent and respond to a spill

of oil or other toxic pollutants and assure

Alaskans that measures are in place to

keep their water and land pristine.”

The bill would raise the per-barrel sur-

charge on oil production from 4 cents to 7

cents.

Several other legislators signed on as

co-sponsors, including Rep. Paul Seaton,

R-Homer; Rep. Peggy Wilson, R-

Wrangell; Rep. Scott Kawasaki, D-

Fairbanks; and Rep. Sam Kito III, D-

Juneau.

Dual accountsSurcharge receipts go into the Oil and

Hazardous Substance Release Prevention

and Response Fund.

The fund, created by the Legislature in

1986, provides funding for pollution reg-

ulators in the Alaska Department of

Environmental Conservation to prevent,

and respond to, oil and other hazardous

spills.

The fund is broken into two parts: a

“response account” for dealing with dis-

astrous spills, and a “prevention account”

that provides operating money for DEC’s

Spill Prevention and Response Division,

known as SPAR.

A 1 cent oil surcharge feeds the

response account, while a 4 cent sur-

charge feeds the prevention account.

The problem, DEC officials told legis-

lators, is that the prevention account is

fast depleting, a consequence of inflation

and declining North Slope oil production.

The 4 cent surcharge currently raises

nearly $7 million a year. Besides the sur-

charge, the prevention account also has

funds from fines, penalties, settlements

and investment earnings.

But the savings balance in the preven-

tion account is expected to run out by fis-

cal 2016.

If the surcharge was raised to 7 cents,

and if oil production were to remain at

current levels, it could generate approxi-

mately $12 million — still short of the

$17 million needed to run the division,

Munoz wrote in a sponsor statement for

HB 325.

However, she said, the additional rev-

enue could “lead to a smaller draw on

unrestricted general funds during a time

of expected deficits.”

Mixed sentiment“With increasing exploration and pro-

duction, and so much new activity in

Cook Inlet and the Arctic, DEC must

maintain its robust spill prevention and

response capacity,” DEC officials told

legislators.

Aside from raising the surcharge for

the prevention account, HB 325 also

would let stand the 1 cent surcharge for

the response account.

Under current law, the 1 cent sur-

charge is suspended once the response

account exceeds $50 million. HB 325

would raise this cap to $75 million.

Munoz noted that the $50 million cap was

set two decades ago, in 1994, and “has

not kept up with inflation since then.”

HB 325 drew support from organiza-

tions such as the Prince William Sound

Regional Citizens’ Advisory Council and

Prince William Soundkeeper.

The supporters noted that 2014

marked the 25th anniversary of the cata-

strophic Exxon Valdez oil spill. They

endorsed HB 325 as an important meas-

ure to address the “budget gap” SPAR

faces in performing work such as review-

ing oil spill prevention and contingency

plans, conducting response drills and

training, and verifying proof of financial

responsibility.

The Alaska Oil and Gas Association

opposed HB 325. AOGA represents most

of the state’s crude oil producers.

In an April 14 letter to the House

Resources Committee, AOGA’s presi-

dent, Kara Moriarty, suggested that “from

the very beginning,” the response fund

had been misused.

“For example, in the first four years of

the fund, the money appropriated was for

things like campgrounds, state airports,

privately owned greenhouses and buying

new ferries. While those were important

concerns, they were not oil spill emergen-

cies,” she wrote.

Moriarty noted that, according to

DEC, oil production and exploration

facilities accounted for only 16 percent of

the volume of product releases in fiscal

year 2013.

“The other type of facilities that

reported spills were mining, maintenance

yard/shops, vessels, air transportation,

canneries and a variety of other facili-

ties,” she wrote.

Moriarty continued: “For the last 25

years, the oil and gas industry has been

the only industry to make any contribu-

tions to this fund and this bill only seeks

to continue that policy by increasing the

surcharge on oil and gas producers to 7

cents per barrel.”

AOGA also opposes talk of expanding

the surcharge to Alaska refineries.

“It is already challenging at best to

operate a refinery in Alaska,” Moriarty

wrote. l

l G O V E R N M E N T

Bill to replenish oil spill fund stallsLegislation would raise the per-barrel surcharge on oil production from 4 cents to 7 cents; oil industry opposes hike as unfair

was a powerful economic incentive that

could well make the difference to the pro-

ducers in whether they do a project, but

he said it would remove a lot of risk to the

state if legislators required the producers

to sell the state’s gas with their own at the

same price.

Everything in parallelTsafos said whether legislators pass

the legislation or chose a different path,

the most difficult thing about LNG is that

everything has to take place in parallel,

not in sequence. You can’t sell gas unless

people know you have gas; you can’t sell

gas without knowing the cost of the proj-

ect — which determines the cost of the

gas.

You can decide in advance, Tsafos

said, but because there are multiple paral-

lel paths that are interdependent you have

to decide everything up front.

On the issue of state involvement only

after the project is sanctioned, Mayer said

that would eliminate the financial risk to

the state during pre-FEED and FEED,

leaving the producers to bear all the risk.

But the producers would have to decide

to do that, he said, which would mean

putting the HOA aside and starting from

scratch and negotiating what he described

as hundreds of pages.

Mayer said as a legislative consultant

he finds slow escalating commitments

going along with work to understand

details of project and bring down risk

appealing compared to past approaches. l

PETROLEUM NEWS • WEEK OF APRIL 20, 2014 15

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continued from page 14

SB 138 UPDATE

Willingness to cooperateBy signing the agreements, the two

First Nations are deemed to have sig-

naled their willingness to cooperate

with LNG development at Grassy

Point.

Natural Gas Development Minister

Rich Coleman said British Columbia is

working quickly to ensure they can

occupy an LNG leadership role.

“Partnership with First Nations,

government and industry will play a

key role to ensure B.C. is in a strong

position to compete in this new global

marketplace,” he said.

Metlakalta Chief Harold Leighton

said his people want to “make sure our

voice is heard when it comes to devel-

opment within our traditional territo-

ry,” adding the agreements “are a good

demonstration of what can be achieved

when we approach development in the

spirit of partnership and collaboration.”

Lax Kw’alaams Mayor Garry Reece

said that working with the government

and the LNG proponents “is positive

progress in our drive to ensure LNG

has real, tangle benefits on the

ground.”

He said the aboriginal community

has “come to a time when the status

quo is no longer acceptable. This is an

opportunity to build an economy and

improve our social situation.”

The government said the agree-

ments raise to 24 the tally of economic

benefit deals it has reached with First

Nations since it launched a jobs plan in

2011 and complete six of the 10 new

non-treaty agreements it has targeted to

reaching over a two-year period.

—GARY PARK

continued from page 1

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do what we do with the oil pipeline, which is come up

with a fair tax structure for the oil companies and the

state of Alaska. That is still an option, but the adminis-

tration is talking as if they are going to negotiate an

agreement that doesn’t allow any taxes. We are going to

have to sell it and that’s called royalty and gas in kind.

That poses a lot of risk to the state.

One of the major risks of taking gas in kind, you have

to commit to the pipeline owner and TransCanada will be

the majority part of the pipeline owner for the part of the

gas that the state shows. You have to pay them as if you’re

using the full capacity of the pipeline. If Exxon, Conoco,

BP end up not selling enough gas, then you still have to

pay for the full amount of the gas shipment charge even if

you don’t have enough gas going through. This cost to the

state for shipping will come to billions of dollars a year.

We don’t know that we are going to fill our part of the

pipeline. We may be paying hundreds of millions of dol-

lars — maybe more, we don’t know — for essentially

unused pipeline capacity.

If we just taxed our natural gas like we do oil, we don’t

bear that risk. The testimony has been in a traditional

pipeline, you use somewhere over 90 percent of your

capacity. That means maybe 5 percent you’re paying for

shipment of gas that isn’t being shipped. That cuts into the

state’s revenue. There have been cases that have turned out

to be worse, according to Rick Harper. We are going

ahead hoping, just hoping, that all of our capacity is filled

in the pipeline so we are not paying for empty capacity

and losing money.

I want an assurance. There are ways to assure that if the

producers don’t produce gas that we need that we are held

harmless. That’s important.

Then there is the problem that the natural gas market is

not 100 percent pretty for us. Right now you can sell gas

at a very high price in Japan — maybe $17 to $19 an mcf

— those are good prices. In some parts of Asia they are

$12 and some they are $14 and others they are $16. If

Exxon, BP and Conoco go and grab those high priced

contracts and we are less sophisticated than they are, we’ll

end up with the low-priced contracts. That might result in

us losing money or getting very little revenue. If we are

going to take on this risk of royalty-in-kind, that one of the

terms we get is that the major oil companies, just like they

do for oil, sell our gas and we get the same terms and

prices as they get.

All of those things right now, the governor says trust

me I’ll negotiate something on those areas. Well, as a sov-

ereign, we should set rules that are fair to the public, not

say, go negotiate. If it’s a bad negotiation you come back

to us and we have all of this pressure to say yes. If we

alter the contract all of these parties will go away.

Petroleum News: Are you concerned that when a con-tract is negotiated, you will have that same rancor over agas line contract that you had during the Murkowskiadministration?

Gara: The governor would do himself a favor and if the

oil companies are interested in this contract, they will do

themselves a favor, and if TransCanada is truly interested

in this contract they will do themselves a favor if they

allow terms into the bill and don’t lobby to defeat terms in

the bill that protect the public. If those provisions don’t

end up in the bill and then a contract comes before the

state that is weak and doesn’t protect the state, then they

face a very real risk with a different Legislature that this

project is going to go nowhere. The smart thing is to set

fair rules now instead of saying let’s just see what happens

during negotiations. We are a sovereign. We have a right

to write laws that protect the public and we should do that.

Petroleum News: Is there anything different in the tenorof the discussions from the AGIA days and the StrandedGas Act days?

Gara: The Stranded Gas Act (contract) came from a

governor who had very little trust and we knew at the time

he possibly constitutionally had the right to cut a contract

without our involvement. That bill was poorly written and

came without very much trust at all. He proposed a con-

tract that he told everybody was a contract that wasn’t a

real contract. Luckily we didn’t go ahead with that

because nobody knew the price of gas was going to tank.

We had a stroke of luck come our way apart from getting

a bad deal. Under Palin, it was different. She was largely

uninvolved but here commissioners were very open. That

was a very open period oddly enough. Now, I like the peo-

ple the governor has personally, but they seem to be wed-

ded to pushing things the governor’s way, always answer-

ing questions not with an answer to your question but with

an argument as to why they are right. If you ask them if

the sky is blue, they will tell you why it’s so good when

the sky is purple. It’s important to me to find out the

answers to questions I have and sometimes I’m not getting

answers to those questions.

Petroleum News: One of the side issues that becamesomewhat divisive was an AGDC board appointment whodid not live in Alaska. Richard Rabinow of Houston wasappointed last fall. Why did this become an issue so late?

Gara: He’s up for confirmation now. A Legislature

can’t stop a bad appointment, that’s temporary, until it

comes time to confirm. It’s also the fact that none or very

few of us, knew that this person was not an Alaskan. I also

want to make sure, in any of our appointments, that we are

not just putting oil company people on our boards. We

need to make sure we put people on our boards who

understand the industry, understand the state’s interest and

will stand up for the state’s interests.

Petroleum News: OK, but you folks brought in RickHarper as a consultant. He’s an out-of-state hire who usedto work for the industry. He might even be a good boardcandidate. How does that differ?

Gara: First of all, the board is the board of directors on

the project for the people of the state of Alaska. We need to

make sure that they are Alaskans so they understand what

Alaska’s interests are. Somebody from California doesn’t

know where Kwethluk is, doesn’t understand that maybe

the project should benefit the people of Kwethluk, or what

the problems are in Fairbanks as opposed to Anchorage as

opposed to the Kenai Peninsula. The board should be

Alaskans who stand up for Alaskans’ interests and not be

beholden to anyone else’s interest. l

continued from page 5

GARA Q&A“If you set the rules up front that are fair to

everybody, where the state doesn’t carry all therisk and in so many provisions the state is

carrying more risk than anybody.” —Rep. Les Gara, D-Anchorage

beginning with the acquisition of

Pioneer’s Alaskan oil and gas opera-

tions,” said Jim Musselman, chief execu-

tive officer of Caelus. “The current

Pioneer Alaska team has the experience to

grow and develop the tremendous

resource potential they have identified.

We believe Alaska offers an enormous

geologic opportunity, coupled with a

favorable regulatory environment for

independent oil and gas companies.”

“We are confident that Caelus can effi-

ciently develop the existing reserves it is

acquiring while building a first-rate oil

and gas company through add-on acquisi-

tions and new discoveries,” said Greg

Beard, Apollo’s global head of natural

resources and senior partner. “We are

delighted to have the opportunity to

invest alongside Jim and his team.”

Pioneer initially announced the sale of

its Alaska assets to Caelus in November

2013, with an expected closing date

around the end of the year. But the

process of tying up the sale took longer

than the companies had anticipated.

Issues that needed to be resolved included

agreements with the state of Alaska over

how deal with the dismantling of the field

infrastructure at the end of field life, and

dealing with royalty relief that has

applied to some Oooguruk leases.

In March the companies announced

that Pioneer had agreed to drop the price

of its Alaska subsidiary from $550 mil-

lion to $300 million, with the company

reporting an accounting cash loss as a

consequence. At the same time, Caelus

said that it was going to take on a $300

million second-lien term loan and a $115

million asset-based loan facility to fund

the purchase and provide working capital

for its operations.

Founded in 2011In November Musselman told

Petroleum News that he had founded the

company in 2011. Musselman said he had

a track record in international oil explo-

ration, going back to the mid-1990s, hav-

ing formed and successfully managed two

companies, Triton Energy and Kosmos

Energy, before forming Caelus.

Musselman said that he had been

investigating oil exploration opportunities

in Alaska when he discovered the oppor-

tunity to purchase Oooguruk, an opera-

tional oil field that would give his compa-

ny an entry to the state, with an existing

asset that is already creating cash flow.

And Caelus sees the continuing develop-

ment of Oooguruk, including the develop-

ment of new oil resources in the field, as a

priority, Musselman said.

On linePioneer purchased the Oooguruk leases

in the nearshore waters of the Beaufort

Sea in 2002 from Armstrong Resources

and subsequently embarked on a fast-track

development of the field. The field went

on line in 2008, and proved successful,

with Pioneer discovering field expansion

opportunities and, in 2009, increasing the

field’s resource estimates by 40 percent.

But, in November 2013, when

announcing the sale of Oooguruk,

Pioneer’s Chairman and CEO Scott

Sheffield said that the sale represented a

strategic move, to focus investment on

shale development in Texas. Sheffield said

that Oooguruk still holds the North Slope

record for the shortest time taken from

first oil discovery to first oil production.

“It’s been a great experience for us and

we thank all our employees,” he said.

—ALAN BAILEY

ration wells for the entire Cook Inlet

basin in 2012.

Ninilchik in 2013The Ninilchik program would follow

up on gas discoveries.

Hilcorp drilled four exploration wells

at the unit last year: the Susan Dionne No.

8, Paxton No. 5, Frances No. 1 and Falls

Creek No. 5. The program targeted gas-

producing horizons, but also included

some of the first oil exploration in the

area in decades.

The 12,000-foot Susan Dionne No. 8

well was non-commercial for oil, but

Hilcorp completed the well for gas pro-

duction from the Tyonek formation in the

Susan Dionne participating area and from

the Beluga formation on a tract basis

within the unit.

The results led Hilcorp to drill the

Frances No. 1 well later in the year from

the new Bartolowitz pad. The well was

also non-commercial for oil, but showed

“strong potential” for gas production

from the Beluga and Tyonek formations.

Hilcorp now plans to test the well toward

the middle of this year with the aim of

starting production in the third quarter.

The company expects to form a Falls

Creek participating area next year.

The Paxton No. 5 well was a shallow

well from the Paxton pad. Hilcorp com-

pleted the well as a producer from the

Beluga formation on a tract basis and is

considering additional activities, includ-

ing the potential for further exploration

activities. The company expects to form

the Susan Dionne/Paxton Beluga partici-

pating area next year.

The Falls Creek No. 5 well encoun-

tered gas in the Tyonek and Beluga, and

now Hilcorp plans to conduct additional

testing this year to gauge the way forward

for development.

Those exploration activities came

alongside a significant workover pro-

gram.

The 2013 program led Hilcorp to con-

tinue exploration activities through 2015,

and the company wants the state to defer

scheduled unit contraction until

December 2015.

Ninilchik in 2014The program for this year calls for six

wells.

The 10,000-foot Frances No. 2 and

Frances No. 3 wells would target the

Tyonek and Beluga formations. The for-

mer would be east of the Falls Creek par-

ticipating area and north of the

Bartolowitz pad and the latter would be

south of the Falls Creek participating area

and east of the Bartolowitz pad. Hilcorp is

describing both wells as “appraisal.”

The 9,000-foot Falls Creek No. 6

would follow up on the Frances No. 2

well to further appraise the Tyonek and

Beluga formations in the area north of the

Falls Creek pad.

The 10,000-foot Paxton No. 6 and

Paxton No. 7 wells would also target the

Tyonek and Beluga formations. They

would both be south of the Paxton pad.

Paxton No. 6 would be an “appraisal”

well and Paxton No. 7 would “follow up”

on the results of Paxton No. 6.

The 6,500-foot GO No. 8 would target

the Sterling and Beluga formations above

the existing Grassim Oskoloff participat-

ing area in the area west of the existing

GO pad.

The program would likely require an

expansion and noise abatement study of

the Paxton pad this year. It would also

require construction of a Bartolowitz gas

facility to support Frances No. 1 gas pro-

duction. The facility would in turn require

boring a pipeline under the Sterling

Highway connecting to the existing

Kenai-Nikiski Pipeline. Hilcorp also

plans to work over the Falls Creek No. 3,

Paxton No. 1 and Grassim Oskoloff No. 7

wells

Deep Creek C PadThe Deep Creek program would

expand exploration at the inland gas field.

Hilcorp began exploring at Deep

Creek in early 2013, drilling the Happy

Valley B-14, Happy Valley B-15 and

Happy Valley B-16 wells from the exist-

ing B pad.

The first wells two tested formations

above the existing production at the unit,

but Hilcorp was unable to reach the target

depth of 5,560 feet with the B-16 well.

This year, Hilcorp plans to complete

the B-16 well, potentially using a side-

track.

The company also plans to drill two

exploration wells from a newly construct-

ed C pad south of the B pad. The 6,000-

foot Happy Valley C-17 well and the

5,000-foot Happy Valley C-18 well

would both target the Sterling and Beluga

formations outside the Happy Valley par-

ticipating area. If successful, the explo-

ration program would likely justify a new

participating area and a gathering line

back to existing facilities, Hilcorp has

said.

Hilcorp also plans to drill Middle

Happy Valley No. 1 well in 2015. The

exploration well would target the

Sterling, Beluga and Tyonek formations.

The program would require a new road

and pad, plus associated facilities and

pipelines to access state and Cook Inlet

Region Inc. land.

The state mentioned the Middle

Happy Valley prospect as early as 2004.

Previous operator Union Oil Company of

California took steps toward exploring it,

but the plans never materialized, leading

to talk of contracting the unit. Given the

exploration program, Hilcorp is asking

the state to delay the scheduled contrac-

tion until the end of 2015.

Hilcorp also plans to work over four

existing wells at the Deep Creek unit this

year: Happy Valley A-7, Happy Valley B-

12, Happy Valley B-13 and Happy Valley

B-14. l

18 PETROLEUM NEWS • WEEK OF APRIL 20, 2014

Conservancy. In September of 2012, the U.S. Fish &

Wildlife Service issued an RFP for theremoval of the two wrecks from PalmyraAtoll and Kingman Reef. Global Diving &Salvage reached out to Curtin Maritime,frequent partners in unique and challeng-ing projects, to collaborate on this.Several factors were fundamental in theplanning process: the safety of personnel and equipment, followed closely by mitigatingthe potential of further damage to the extremely delicate living coral and reef structure.Working together a creative plan was developed to remove the wreckage from the inner-tidal areas. Flat deck scows were designed and built with shallow draft to transit thedebris across the coral reef areas to the main barge that provided logistical support andhousing for the project.

In total, the combined crew of 12 worked 79 days with 880 hours spent underwater tocut, rig and remove over 970,000 pounds of steel and debris, as well as 605 gallons ofhydrocarbons.

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

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OIL PATCH BITS

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HILCORP PLANS

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SUBSIDIARY SALEPioneer purchased the Ooogurukleases in the nearshore waters ofthe Beaufort Sea in 2002 from

Armstrong Resources andsubsequently embarked on a fast-

track development of the field.

years working for ExxonMobil in Russia,

Southeast Asia and the Middle East.

That experience put him in the forefront

of those able to assess who else is compet-

ing for a piece of the global LNG action.

What he brings to the table is a belief

that Imperial will need more natural gas

resources than it already controls, although

he will not say whether the company’s

stranded reserves in the Mackenzie Delta,

that would have underpinned its operator

role in the Mackenzie Gas Project, could

find a place in the WCC project.

But he said that an LNG proposal can-

not not have enough quality gas resources.

More important now is the time that will

be needed to evaluate the company’s exist-

ing acreage and assess its LNG potential,

especially since Imperial’s C$3.1 billion

takeover a year ago of Celtic Exploration,

with the greatest prize in the transaction

identified as 13 tcf of potential gas in the

Montney area of western Alberta.

That includes a selective program of

drilling to understand “where the highest-

quality, best portions of the acreage are and

where we’ll get the highest profitability.”

Kruger is not swayed by those who

believe LNG from Canada could fetch

US$14-$18 per thousand cubic feet in

Japan or South Korea.

The company has indicated that answers

to questions such as the possible commer-

cial returns from LNG exports, engaging

governments on fiscal and regulatory mat-

ters, evaluating pipeline options from the

gas fields to the British Columbia coast and

choosing a site for an LNG terminal as well

as scoping that facility’s size and cost are

part of an undertaking that could take sev-

eral years to complete.

Paul Masschelin, Imperial’s senior vice

president of finance, told an investor con-

ference in New York earlier in April that the

time is needed “before we will find our-

selves in a position to determine whether an

LNG opportunity on the West Coast of

Canada can, or would be an attractive

opportunity to pursue.”

Despite receiving an export permit,

Imperial and ExxonMobil are still in the

“very early evaluation stages,” he said, not-

ing that LNG ventures are very complex

projects.

Kruger told reporters Imperial has no

intention of rushing decisions because it’s

“afraid we might miss out. ... It has to be a

quality project. All aspects have to fit ... not

least of which is the fiscal and regulatory

regime” which the British Columbia gov-

ernment has yet to finalize.

Offering what could be a mantra for

Imperial and ExxonMobil, he said that pro-

ceeding with a project will hinge on

whether the partnership believes “there’s

value and a place in the market (otherwise)

it won’t go.” l

The Cook Inlet area gas supply forecast has

increased, which is a positive development

for local utilities. LNG exports will provide

a market opportunity for Cook Inlet gas pro-

duction in excess of local market demand.”

U.S. Sen. Lisa Murkowski, R-Alaska,

expressed her support for the renewal of

LNG exports.

“I’m glad ConocoPhillips will be able to

add to Alaska’s 40-year history of supplying

natural gas to Japan,” Murkowski said.

“Today’s announcement by DOE also high-

lights the growth that’s occurring in Cook

Inlet, where there is now ample gas supply

to both meet local needs and help out our

friends overseas.”

U.S. Sen. Mark Begich, D-Alaska, said

that he had urged the Department of Energy

to fast-track ConocoPhillips’ application for

exports to non-free-trade-agreement coun-

tries such as Japan. There is currently a

queue of similar applications for planned

LNG facilities in the Lower 48.

“This is great news for the cradle of

Alaska’s oil and gas industry on the Kenai

Peninsula,” Begich said. “With plenty of

gas available to meet local needs through at

least 2018, we’re seeing the kind of job

growth responsible oil and gas development

can provide.”

A changing marketGiven a recent debate about potential

shortages of Southcentral utility gas from

the Cook Inlet basin, it may appear counter-

intuitive to see the authorization of gas

exports from the basin. Indeed, in early

2013 ConocoPhillips, citing uncertainty in

the local gas market, mothballed the Nikiski

LNG plant when a previous export license

expired.

But with companies such as Hilcorp

Alaska and Cook Inlet Energy revitalizing

Cook Inlet gas production, and with multi-

ple companies exploring in the basin and

bringing new gas fields on line, the gas sup-

ply situation has changed dramatically in

recent years. The Southcentral Alaska gas

and power utilities have now all secured

contracts to fully meet their gas supply

needs through to the first quarter of 2018.

And, with Hilcorp having furnished the

bulk of those contracts, other companies

have been expressing concern about finding

markets for new gas, should gas exploration

prove fruitful.

In fact, in September 2013 the Alaska

Department of Natural Resources, or DNR,

wrote a letter to ConocoPhillips, asking the

company to apply for a new LNG export

license and citing the changes in the Cook

Inlet gas market.

Sufficient suppliesIn approving the export licenses, the

Department of Energy has recognized the

turnaround in the Cook Inlet gas industry.

The agency, referencing the DNR letter and

a DNR report on Cook Inlet gas resources,

said that ConocoPhillips had provided “sub-

stantial evidence projecting a future supply

of natural gas in the Cook Inlet region suffi-

cient to support both the proposed export

authorization and regional demand for natu-

ral gas during the two-year authorization

period.” And, in its analysis for the new

license, the Department of Energy also cited

a comment by DNR that an operating LNG

plant could invigorate the Cook Inlet gas

industry by providing a market for gas pro-

ducers.

DNR had also commented that LNG

production provides a vital role in gas sup-

ply security in Southcentral Alaska during

periods of high winter gas demand, by

enabling the diversion for utility use some

of the gas otherwise earmarked for LNG

manufacture. In addition, by providing a

steady market for gas during the summer,

when utility demand is low, the LNG

plant can ensure the continuity of gas well

operation, thus maintaining overall well

performance and improving gas resource

recovery, DNR had said.

The operation of the LNG plant also

provides employment on the Kenai

Peninsula. l

PETROLEUM NEWS • WEEK OF APRIL 20, 2014 19

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GAS EXPORTS

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TREADING CAREFULLYC

ON

OC

OPH

ILLI

PS

ConocoPhillips’ LNG facility at Nikiski on the Kenai Peninsula.

20 PETROLEUM NEWS • WEEK OF APRIL 20, 2014

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