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Artek Exploration Ltd.

(RTK-T)

Liquids Growing One Play at a

Time

January 15, 2014

Kuno Ryckborst

(587) 350-6577

[email protected]

• Continued exploration success should lead to

strong y-o-y reserve growth. Management has

already de-risked one condensate rich natural gas

play and is in the process of proving up a second at

Inga/Fireweed in NEBC, plus it has just spudded its

third Triassic light oil window in the Peace River Arch

region of Alberta where industry has been booking

good development success.

• Dominant focus on condensate yield (initial C5+

rates of 100 up to 300 bbls/mmcf Doig; and 100 up

to 200 bbls/mmcf Montney) to drive operating

netbacks from $16.46 in 2012A to $27.55/boe in

2014E. The price outlook for condensate is very

bullish in Alberta (garners a 7% to 15% premium to

Edm. Par) as it is required to dilute bitumen and

heavy oil for pipeline transport to market.

• Artek is a compelling take out or merger

candidate. We believe that the company is in the

early stages of firming up the Montney play with

high conviction on existing Inga/Fireweed lands.

Likely buyers are large cap or majors with large

Montney capex budgets that are currently drilling in

the immediate vicinity (i.e. Tourmaline Oil (TOU-T).

We also view Kelt Exploration (KEL-T) as the most

likely merger candidate given its varying ~40% to

50% W.I. in the two LRNG plays at Inga/Fireweed.

We are initiating coverage with a speculative BUY

recommendation and a 12-month price target of

$4.30 based on 2014E multiples of 6.9x EV/DACF

and $61,000/boepd.

$4.30$3.60

$4.30

19%

Realized Prices 2012A 2013E 2014E

Light Oil ($/bbl) $80.78 $90.54 $90.28

Natural Gas ($/mcf) $2.67 $3.30 $3.58

Production

Crude oil & Liquids (bbls/d) 1,106 1,416 2,431

Natural Gas (mcf/d) 9,968 13,643 20,598

Total Production (boe/d) 2,768 3,690 5,864

Oil & Liquids Weighting 40% 38% 41%

Financial ($MM, except Per Share item)

Revenue $41.1 $58.6 $97.0

Net Income -$2.2 $2.7 $13.0

DACF $18.1 $28.0 $51.5

CAPEX $59.9 $79.1 $57.8

Net Debt $48.9 $65.7 $72.7

Net Debt/CF 2.9x 2.4x 1.4x

CFPS - Fully Diluted $0.37 $0.40 $0.70

NAVPS - Fully Diluted $4.51

Closing Price $3.23 $3.60 $3.60

P/CFPS 8.8x 9.0x 5.1x

EV/DACF 11.9x 11.0x 6.1x

EV/BOEPD $77,916 $83,107 $53,497

EV/P+P boe $7.3 $10.3 $10.6

P/NAVPS 72%

Shares Outstanding, Basic (MM) 66.9

Shares Outstanding, Diluted (MM) 71.8

Insider Holdings, Diluted 25%

Market Capitalization (MM) $241

Enterprise value (MM) $307

52 Week Price Range $2.87-$3.88

Valuation

Initiating Coverage

Speculative BUYPrev ious Close

12-month Target Price

Potential Return

Stock Data

About the Company

Artek Exploration Ltd. is a domestic oil and gas company. The

company principally holds interests in three exploration areas

located in the Peace River Arch of Northwestern Alberta;

three exploration areas located in the Deep Basin of

Northeastern British Columbia/Northwestern Alberta; three

exploration areas located in the Inga/Fireweed area of

Northeastern British Columbia and the Leduc Woodbend

property located in Central Alberta. The company was

founded on December 12, 2004 and is headquartered in

All prices in CA$ unless otherwise stated

Stock Performance

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mailto:[email protected]

January 15, 2014 | Page 2 Kuno Ryckborst | 403-354-3598 | [email protected]


Table of Contents

Investment Thesis ................................................................................................................. 3

Company Profile and Capital Structure ............................................................................. 6

Potential Catalysts ............................................................................................................... 8

Management and Directors ............................................................................................. 11

Core Property Overview .................................................................................................... 12

Forecast ............................................................................................................................. 19

Well Economics .................................................................................................................. 24

Key Risks ............................................................................................................................. 26

Recommendation ............................................................................................................. 30

Appendix A – Management and Directors ...................................................................... 32

Appendix B – Historical and Projected Financial Statement ............................................ 33



Investment Thesis

Artek Exploration Ltd. is a domestic junior oil and gas producer focused on

de-risking several prolific liquids rich natural gas (LRNG) plays targeting the

condensate rich Doig and Montney formations at its Inga/Fireweed property in

northeast BC (NEBC). Management is also in the early stages of proving up a

third Triassic play (Charlie Lake light oil) that offers multi-zone potential for

light oil and associated natural gas from up to five prospective formations

notably the Upper Montney, Charlie Lake and Halfway. The company also

holds six other natural gas focused projects within the Peace River Arch and

Deep Basin areas of Alberta and British Columbia.

Compelling Reasons

We believe Artek to be an appealing investment opportunity given the

following: 1) operator of a controlling 50% to 60% W.I. in one proven, and

two prospective, Triassic plays on its Inga/Fireweed lands; 2) management

developed a well-defined exploration concept and strategy and then

successfully executed the Doig natural gas and condensate pool that offers

both scalable production and reserve growth, and 3) prioritizing the

exploration of the Montney formation to prove up a second LRNG play at

Inga/Fireweed that we believe should lead to a possible takeout or merger

event.

Proven Drillers Management is a technically astute exploration team that has grown

production primarily through the drill bit from zero at inception in Jan. 2010

to exit 2013 at ~4,900 boe/d (~38% oil and liquids). Management uses a

combination of its technical exploration expertise and several large core land

holdings in the deep basin to give it a competitive advantage in proving up

early day resource plays that offer investors risked return on reserve growth.

All key members of Artek’s management team held positions of V.P. or

manager level at their previous companies (e.g., AEC, Pan Canadian,

Fairborne Energy, Chevron, Petro-Canada, Ketch Resources Ltd., Mustang

Resources Ltd., Kereco Energy Ltd., Renaissance Energy Ltd. and Galleon

Energy Inc.).



Potential Catalysts Management is in the early stages of potentially firming up the Montney play

with high conviction on existing Inga/Fireweed lands where it has assembled

120 (71 net) sections with Montney rights. Management has drilled two gross

Montney exploration wells to date, and we expect the company should make

public its third Montney well results by the end of January, 2014. We expect

higher test and IP30 rates simply because this well will be stimulated using a

much larger 30 stage slick water frac that should crack the rock more

significantly than the smaller nitrogen base and propane fracs performed on

the first two wells. Notwithstanding, we believe it will take until at least the

summer of 2014 at the earliest before any meaningful flow history has been

established.

Also, concerted effort to continue to step out its drilling success targeting the

Doig formation has extended this condensate pool in both a northerly and

southerly direction. A similar LRNG reservoir potentially exists on its Fireweed

lands, which along with new proprietary 3-D seismic could significantly

increase horizontal drilling locations to 74 (43 net). Comparatively, Sproule

assigned only 24 proven undeveloped (PUD) drilling locations at Inga and

three at Fireweed in the 2012 NI 51-101 reserve report). We expect material

reserve additions from three gross Doig wells that very recently came on as

flush production enabling management to meet exit guidance of 4,800 to

5,000 boe/d. Two of the three were successful outpost wells that de-risked an

additional ~6 sections at the south end of the Doig sand bar defined over a

~22 to 25 section trend, plus it encountered 15 meters of thicker pay (65 vs.

40 meters) than reported at the north end. These wells reported an IP30 of

1,200 boe/d (53% liquids) and tested at 1,693 boe/d (61% liquids), which is

within the average range for a typical Doig well.

Likely Take-out Candidate Similar to 2012 when management was focused on exploring the Doig

formation, Artek is once again in the early stages of potentially firming up the

Montney play with high conviction on existing Inga/Fireweed lands where it

has assembled 120 (71 net) sections with Montney rights. This exploration

potential plus the Doig success, where it holds 107 (61 net) sections of Doig

rights, make Artek a very compelling and realistic takeout candidate. Likely

buyers of Artek are companies that are currently drilling in the immediate

vicinity and have committed extensive Montney capital expenditure budgets

(i.e. Tourmaline Oil Corp (TOU-T, not rated) and Bonavista (BNP-T, not rated)

or majors like Royal Dutch Shell and Petronas/Progress, not rated).



Should the unlikely event occur where the company is not purchased,

management has sufficient net inventory (inventory of 228 net wells) to grow

corporate production beyond 10,000 boe/d. These drilling prospects are

comprised of 43 net LRNG Doig prospects at Inga/Fireweed supported by a

large inventory of natural gas prospects representing >500 mmboe of 2P

reserves. No Montney and Charlie Lake drilling locations are included in this

number. These natural gas projects have limited appeal to potential

purchasers today, but we believe management will spin-out for itself should a

successful sale or merger process occur given the likelihood of LNG export

potential (2018E to 2020E) from northeast British Columbia (NEBC).

From a mergers perspective, we see Kelt Exploration Ltd. (KEL-T) as the most

likely merger candidate given its assets overlap as it could provide many

synergies that could enhance its valuation further from Kelt’s existing

management team. In order for a merger to occur, the valuation gap between

Artek and Kelt will need to close. Given that Mr. David Wilson is an Artek

board member means he would abstain from all such discussions.

Valuation and Recommendation We are initiating coverage with a BUY recommendation and a 12-month

price target of $4.30 based on 2014E multiples of 6.9x EV/DACF and

$61,000/boepd.

Artek currently trades at 5.1x EV/DACF and $53,000/boepd multiples based

on our 2014E estimates. This compares to ~$67,000/boepd based on 2014E

consensus estimates from our selected peers.

Even before considering the additional value created in 2013, our 12-month

target price is supported by the fact that Artek’s current share price is trading

at a 24% discount to its most recent net asset value of $4.51 per share on a

2P basis, or ~0.95x our 12 month target. This NAV was based on Sproule’s

most recent NI 51-101 compliant reserve report dated Dec. 31, 2012.

In 2013, management has added additional reserve value by bringing liquids

to surface from 2 (1.2 net) Montney exploration wells at a rate between 114

and 124 bbls/mmcf, discovering a new natural gas driven light oil play at its

Mulligan property in the Peace River Arch, and extending the northern

boundary of its condensate pool at Inga. When all is said and done,

management will have allocated ~37% of its $85.3 million 2013E capex

program on exploration projects to create reserve value upside that we feel is

imminent in the upcoming Dec. 31, 2013 Sproule reserve Report (March

2014).



We view the risk-reward to investors at the current valuation as compelling

with the potential for further share price appreciation as Artek continues to

drill, frac and test the Montney resource play and prove up the 120 (71 net)

sections that it holds together with Kelt Resources.

Company Profile and Capital Structure Despite its focus on exploration, the company has always been well

capitalized using the proper blend of debt and equity capital. Artek currently

has 66.9 million shares outstanding of which insiders hold approximately 25%

of the basic shares outstanding broken down as follows: director David Wilson

holds 5.4%, director Bruce Chernoff 6.82%, director Rafi Tahmazian 3.92%

and senior management 15.6%.

Based on the recent share price of $3.63, Artek’s market capitalization is

~$241 million, and after including our 2013E net debt estimate of $65.6

million (guidance is $65 million) equates to a current enterprise value of

~$307 million.

As at September 30, 2013 (end Q3/13), Artek reported a working capital

deficit of $68.9 million driven by $37.9 million drawn on its borrowing base

facility (currently authorized at $90mm) and $50.8mm in outstanding

payables versus current assets of $19.7mm. We are forecasting 2014E net

debt of $72.7 million, or 1.4x Net Debt to cash flow.

When debt approached higher levels in the past, management was either

successfully able to sell a small working interest in its Leduc light oil property

(sold 218 boe/d weighted 94% to light oil in Jan. 4, 2012 for $19.4 million,

or $89,000/boepd of $30/boe on a 2P basis), or raise equity capital (most

recently raised ~$17.1 million gross by issuing 4,242,000 common shares on

a flow through basis).



Exhibit 1: Company profile

Source: Company reports, Beacon Securities Ltd.

Artek shares are up ~26% from the 52 week low and have performed very

well since the summer low natural gas price environment experienced in July

2012. Still, we firmly believe there is still upside potential to the share price.

This return should come from the appeal of having ~74 (43 net) scalable

LRNG Doig wells (~6 year drilling program at 7.2 net wells per annum) with

very strong yielding C5+ (up to 300 bbls/mmcf) at Inga/Fireweed, plus the

exploration upside attributed to both (i) the Montney acreage at

Inga/Fireweed; and (ii) Charlie Lake play at Mulligan (Peace River Arch,

Alberta) where industry has de-risked much of the neighbouring lands at Spirit

River, Cecil and Earing.

Exhibit 2: Relative return versus Canada S&P/TSX Composite

Source: FactSet



Potential Catalysts

Montney, Montney and Montney… For the foreseeable future, management is focused on proving that the LRNG

driven Montney Formation in NEBC runs through its sections of land. Similarly

as an operator, management has drilled three gross Montney exploration

wells to date, and we expect more impactful well results by April 2014E at the

earliest before meaningful flow history has been established.

Given that it is still early stages of exploration, the company is still

experimenting with ways to find the optimum completion technique. As such,

we remind investors that it took approximately six gross wells in 2012 before

management figured out the best way to drill and complete a LRNG Doig well

with a type curve that exceeded Sproule’s initially assigned type cure of its

2011 reserve report. Management has been able to achieve an average IP30

flow rate between 1,000 and 1,200 boe/d surpassing Sproule’s assigned IP30

flow rate of ~900 boe/d.

The first well was completed using a Nitrogen foam frac and sanded off

several frac stages. Furthermore, it encountered a blockage in the heel on drill

out. As a result, this well only flowed at IP30 220 boe/d weighted ~46% to

liquids yielding 102 bbls/mmcf of which 85% is C5+. The second well

recorded a much better result and management experimented with a

hydrocarbon frac (similar to the propane fracs it uses to complete the Doig

wells). This well flowed at IP30 of 637 boe/d weighted ~45% to liquids

yielding 114 bbls/mmcf, 77% condensate. The third was drilled late Q4/2013

where management is experimenting with a much larger 30 stage slick water

frac. The slick water will enable it to pump more fluid down hole with much

greater force with the intention to create larger cracks and force longer

penetrating fissures into the rock.

Management should make public its third Montney well results by the end of

January, 2014, after flowing back fluid over the remaining weeks of the

month. We expect higher IP30 flow and test rates simply because slick water

fracs enable you to pump more volume and pressure down-hole, thereby

creating larger fissures to penetrate the tight rock.

Given the industry is still de-risking the Montney in NEBC, we have

conservatively modelled new production from the Montney using an IP30 flow



rate of 640 boe/d (35% liquids), 65% first year decline rate (18% thereafter),

with a D/C/T of $7 million and EUR of 550 mboe per well.

This compares to Bonavista’s (BNP-T, not rated) Montney play at Blueberry

(situated directly northeast of Inga/Fireweed) that has encountered IP30 rates

between 300 and 1,1100 boe/d yielding liquids at 155 bbls/mmcf of which

52% is C5+. Given that it drills more efficiently by using a dedicated rig, the

D/C/T is $6.5 million with a EUR of 502 mboe per well. Bonavista intends to

drill 49 gross Montney wells thru 2018 allocating ~$319 million to

developing this LRNG play.

The important proof of concept is whether the liquids yield is similar to Artek’s

Doig play where ~50% of the liquid content on average IP30 is in the form of

condensate, which garners a premium to Edmonton light oil prices.

Condensate, C5+ or natural gasoline, as it is otherwise known , is used as a

diluent to transport heavy oil sands down the pipeline from Ft. McMurray.

Doig wells tend to generate ~150 bbls/mmcf of condensate on average at

IP30, whereas the Montney play in NEBC in still deemed to be exploratory in

nature and requires more de-risking. Initial indications are for condensate

yields of ~100 bbls/mmcf at IP30.

We view this demand for condensate to remain strong as it is a major additive

(350,000 boe/d demand vs 145,000 boe/d supplied – source National

Energy Board) to transport ~2 mmbbls/d of bitumen (SAGD and Mining) to

market via pipeline. As such, condensate garners a 7% - 13% premium to

Edmonton Par oil prices in Alberta. Although condensate is abundantly

produced in the US, there is a shortfall in Alberta.

These catalysts represent sufficient upside from Artek’s current share price

should management continue to prove that the Montney resource play exist on

its Inga/Fireweed lands. Several majors (i.e. Shell and Petronas/Progress) are

spending large Montney capex budgets by drilling in the immediate area;

Petronas/Progress to the northwest and Shell and Tourmaline in a southeast

direction from Inga/Fireweed. Proving that the Montney exists on this acreage

makes this multi-formation condensate property very attractive.



Exhibit 3: LRNG regional Montney & Charlie Lake light oil resource plays

Source: Company reports.

PRA – Mulligan This is an early stage exploration play where Artek holds 65 (60 net) sections

of land of which 32 (30 net) sections are on trend with several Triassic sub-

cropping’s prospective for 32 - 40 degree API oil and associated natural gas.

Artek has identified ~20 horizontal drilling locations at 100% W.I that

produce light oil and solution gas from up to five formations, notably the

Upper Montney, Charlie Lake and Halfway Formations. Artek drilled its first

two exploration wells at Mulligan that tested 637 boe/d (15% oil) and 500

boe/d (62% oil), respectively, targeting the Charlie Lake formation and has

spudded the third well early January, 2014.

Artek’s land positioned is sandwiched between two active drilling movements

at nearby Spirit River and Cecil properties. Tourmaline (TOU-T, not rated)

announced a major expansion on July 4, 2013 to its Peace River High and

Spirit River Charlie Lake play that is situated very close to Artek’s Mulligan

area lands. Tourmaline is delineating various structural oil and gas pools

having successfully drilled 43 Charlie Lake oil wells along this trend since

2011. The average 2P reserves per well is ~300 to 500 mboe and

Tourmaline plans to drill up to 75 wells by FYE 2014.

Industry is de-risking adjacent lands at four to six wells per section, suggesting

that this play could add between 120 and 180 additional well locations



representing a new core area. The fact that Tourmaline has surrounded much

of Artek’s land position in the vicinity further validates our thesis that

Tourmaline could be a likely acquirer. The company recently press released

(Jan. 6, 2014) that it is producing ~ 9,600 boe/d (59% oil) at Spirit River, plus

that it has drilled an additional five successful Charlie lake delineation oil

wells at Mulligan.

Management and Directors Artek is run by an experienced and technically proficient management and

Board. They have a history of starting junior E&P companies and growing

them to a certain production level and reserve base with a pre-determined exit

strategy. Key members previously played an integral role in taking Ketch

Resources Ltd. from 1,600 boe/d to over 10,000 boe/d, which it successfully

sold to Ketch Resources Trust (Advantage Energy Income Fund) in 2002 for

$500 million.

All key members of Artek’s management team held positions of V.P. or

manager level at their previous companies (e.g., AEC, Pan Canadian,

Fairborne Energy, Petro-Canada Chevron, Ketch Resources Ltd., Mustang

Resources Ltd., Kereco Energy Ltd., Renaissance Energy Ltd. and Galleon

Energy Inc.). They did an admirable job of navigating through a challenging

natural gas commodity price environment in 2012 and have now positioned

the company for profitable growth for 2013E and beyond by executing its

corporate strategy.

Artek is led by a Board of Directors with important relationships and proven

track records of building successful exploration and production companies

(Harvest Energy Trust, Pacalta Resources Ltd., Celtic Exploration and Ketch

Energy Trust).

Management has a proven ability to access bank and equity capital even

during challenging market conditions. Most recently, Artek successfully raised

$17.1 million of gross equity proceeds on a bought deal basis, and increased

its borrowing base credit facility from $75 to $90 million in October 2013.

We refer the reader to Appendix A that expands further on both senior

management and the Board of Directors.



Core Property Overview

Artek currently has four core properties as outlined in Exhibit 4 below. Its

Inga/Fireweed and Deep Basin properties are situated in northeastern British

Columbia and both represent liquid-rich natural gas plays. The Peace River

Arch properties in northwestern Alberta feature multi-zone oil and natural gas

formations, while the Leduc/Woodbend property represents a small unitized

oil play situated in central Alberta.

Artek reported an aggregate land position in 2012 of 229,969 gross

(157,687 net) acres valued by Seaton-Jordan & Associates at $35.6 million.

The land position is split 60,200 (36,841 net) acres as developed and

169,740 (120,846) as undeveloped. The acreage is situated 53/47 in B.C.

with the single largest land position held at the Inga property. On Aug 1,

2013, management added 11,227 net acres of land from Pengrowth

(formerly NAL).

Corporately, the Company has identified over 228 drilling locations, of which

35% have been earmarked for light oil and liquids with a primary exploration

and development focus of drilling high impact LRNG wells at Inga from three

prospective Triassic Formations.

Exhibit 4: Core operating areas & Inga/Fireweed acreage

Source: Company reports



Inga/Fireweed, Northeastern British Columbia Inga represents the Company’s marque growth property where it is partnering

with Kelt Exploration Ltd. on a 60/40 basis. Together, they are targeting two

liquids-rich natural gas pools and one light oil play by drilling horizontal wells

into the following three Triassic Formations: Charlie Lake, Doig and the

Montney (listed from shallowest to deepest).

Doig Formation:

The Doig reservoirs are extensive (two-and-a-half by eight-mile fairways)

upper and lower sand bars that are comprised of marine and shore face

sands. Millions of years ago, vicious hurricane-type storms removed hundreds

of miles of coastal beach with the stormy water whipping the sand into

suspension until the sand gradually settled out in deeper less turbulent water

to form several miles of deeper water offshore sand bars. These recurring

storms continuously churned up shoreline beaches and coastal sand barriers

depositing the sand further out along these offshore sand bars.

The eroding coastlines were subsequently re-deposited with a fresh source of

sediment by extensive river and drainage systems. This recurring cycle

continued over many millions of years forming the upper and lower sand bars

that range in thickness between 20 and 50 meters and are known today as

the Doig formation (see Exhibit 5 below).

Exhibit 5: Cross section of the Doig sandbars




The lithology of the reservoir rock is comprised of fine-grained quartz

sandstone to siltstone and shale. These sand bars were compressed over

millions of years and the resulting porosity is about 20%, which is unevenly

distributed throughout this heterogeneous formation causing erratic

production rates and declines. The Doig formation gets oilier as you go south

down the trend.

Production from the Doig formation is weighted about ~35% to liquids. New

additions tend to come in large chunks with high initial production rates (IP)

and steep initial declines. Extensive 3D seismic (347 km2

) was used to identify

the Doig pool, which appears to underlie the majority of Artek’s land position.

The company has compiled its largest land holding here with 107 (61 net)

sections of land on the Doig trend plus additional deeper rights. Artek’s large

inventory of well locations and sizeable land position is attributable to the fact

that it has been in the area for a while. Management believes that recent well

results and seismic mapping support at least 43 net horizontal well locations.

This represents about six years of drilling inventory assuming 7.2 net wells per

annum at less than three horizontal well spacing per section. Unlimited down

spacing per section is permitted by the B.C. Government, but engineering

currently supports a minimum of four wells per section. Both the low

permeability and high liquids ratios encountered in the Doig pool thus far

support the potential for a horizontal well density greater than three.

Key surrounding players are Athabasca Oil Corporation (ATH-T, not rated),

Paramount Resources Ltd. (POU-T, not rated) a former Breaker Energy

position, Canadian Natural Resources (CNQ-T, not rated), Storm Resources

Ltd. (SRX-V, not rated); Yoho Resources Inc. (YO–V, not rated) and Baytex

Energy Corp. (BTE-T, not rated). Despite its 60/40 partnership with Kelt with

respect to the Doig mineral rights, Artek operates a vast portion of the joint

production until delivery to two third party deep cut facilities (the McMahon

and Stoddart gas plants). The Inga/Fireweed property was secured via its Nov.

2009 corporate acquisition of a small private company, Rising Sky Energy Ltd.

Given that this is a geotechnical play, with a minimum target resolution of 20-

metre thickness, management has confidence in its seismic interpretation

locating the reservoir rock depositional estuaries. Operationally, Artek is

predominantly targeting the thicker Doig pay zones first (30 to 65 meters

thick) in its development drilling program. The rock type and resulting porosity

and permeability remain relatively unknown until confirmed by results derived

from drilling, coring and testing more wells (currently Artek has drilled and

completed five wells).



Montney Formation:

The Montney Formation is predominantly an LNG driven resource play

comprised of a tight sands of Triassic Age that lies within the greater Deep

Basin. This fairway spans a 110 km long corridor in a NW to SE trending

direction that runs from Fort Nelson, BC, beyond Fort St. John, to the Hinton

area in west central Alberta.

The Montney ranges in formation thickness between 270 and 300 meters with

the thickest interval found in the Foothills region of Alberta, and typically thin

in both an eastward direction towards the erosional edge of the basin, and

northern direction up to Ft. Nelson, BC. The Montney Formation is

unconformably overlain by the above targeted Doig Formation.

The BC Montney play trend is predominantly being de-risked in two directions

driven by Shell, Tourmaline and Arc drilling a NW direction, and

Progress/Petronas, Tourmaline, Shell and Bonavista that are drilling in a SE

direction. These intermediates and majors have committed large 2014 capex

programs to further delineate this attractive LRNG play. What make this play

attractive is strictly the lucrative Edmonton Pentane Plus prices, as Montney

wells appear to produce between 100 – 200 bbls/mmcf of condensate at

IP30. As per the BC Oil and Gas Commission, FYE Montney production in

2012 averaged > 1.5 Bcf/d which represented more than ~41% of BC’s total

natural gas volumes. Artek’s 120 (71 net) sections of land at Inga/Fireweed

with Montney Rights are situated in the middle of these two converging drilling

movements. Should management thus prove near-term exploration results

that the Money Formation runs through its lands and is hydrocarbon charged

with similar industry type curves, it would add both luster and appeal to

Artek’s 20 to 60% W.I. in the Montney/Doig Rights land position as a takeout

candidate.

The Montney Formation is divided into three layers, comprised of the Upper,

Middle and Lower intervals, all three of which are prospective for hydrocarbon

recovery. Most of the drilling targets the Upper Montney where the pay is

thicker and appears to contain more organic rich sediments. The lithology of

the Montney Formation is organic rich shale inter-bedded with siltstone in the

western part of the formation migrating to finer grained sandstone on the

eastern flank. Tight sand and silt stone typically have reasonable porosity

between 6% - 10%, but due to the compactness of the spherical molecules it is

characterized by low permeability, which can be undesirable (very tight) at less

than 1md. Recovery of natural gas and associated liquids from this formation

is successfully executed via horizontal drilling and requires modern completion

technology in order to fracture and stimulate formation flow. Similar to Inga,



the higher the number of fractures per horizontal leg, the higher the initial

production (IP30) rates. Industry results from the Montney even suggest an

upward shift in production rates and the resulting type curve that are leading

to greater first-year recovery.

If successful, we would expect management to book similar EUR of 550 mboe

per well based ~25% recovery factors as posted by competitors in the

surrounding vicinity. We also expect ~65% of the production to be in the form

of natural gas and ~35% as liquids. The aforementioned remains to be

qualified, as management have only drilled two gross wells and have not as

yet delivered any well economics to the market.

Charlie Lake Formation:

The third Triassic play situated at Inga/Fireweed is the Charlie Lake

Formation. Last year, Artek drilled and tested this formation baring oil as per

the 2012 press release. While drilling through what was confirmed as the

Charlie Lake, Artek encountered higher than normal well-bore pressure and

pressure kicks causing well control issues that required an increase in mud

weight. The well was drilled down to the target Doig Formation will thus

require more evaluation. The formation tested 200 bbls/d of light oil from a

70 hour test flowing through a vertical well bore that was only perforated. The

well was eventually completed as a deep Doig well but management will

continue to test this shallower formation as it continues to drill Montney and

Doig exploration wells.

The Alberta Energy Regulator (AER), formerly the Energy Resources

Conversation Board (ERCB), did not grant a co-mingling production permit at

the time. Furthermore, it will be difficult to co-produce a liquid and gas from

two separate formations with different reservoir pressures. Management

intends to shut-in the Doig production once volumes fall below 200 boe/d

and at that point will again test the Charlie Lake interval by flowing oil up

tubing for several months to collect additional well data.

Peace River Arch, Alberta Artek’s Peach River Arch (PRA) properties is comprised of 77 net sections with

Nordegg natural gas rights acquired through various Crown land sales and

farm-in agreements between 2005 and 2010, and 65 (60 net) sections that

are prospective for several sub-cropping Triassic oil plays. At PRA, the

Company is currently focused on a triangular land position within the Cecil,

Dunvegan and Mulligan properties that offer with multi-formation

hydrocarbon potential from the Gething, Montney, Charlie Lake, Doig and

Halfway formations.



The PRA is a large-scale tectonic uplift that stretches ~750 km from

northwestern Alberta into northeastern B.C. and is centered on the town of

Grande Prairie, Alberta. The greater PRA area is predominantly known as a

natural gas and LRNG region, however oil is being recovered more recently in

the shallower Triassic sandstones found in northwestern Alberta. It is here that

Artek is focusing its preliminary exploration activities.

Management is targeting a series of reservoirs trapped at depths between

1,200 and 1,400 meters that appear to follow a northwest to southeast trend

that meanders through Artek’s land position. The transgressive stage of the

early Triassic geological period produced depositional layers of marine

sandstone that were subsequently trapped due to the faulting of the

underlying formations during the tectonic activities that formed the PRA.

Management is focused on exploring the 32 (30 net) sections that are directly

applicable to this play that is on trend with various Triassic oil windows. The

Company has identified ~20 exploratory drilling locations at 100% W.I that

produce light oil and associated natural gas from up to five prospective

formations notably the Upper Montney, Charlie Lake and Halfway.

Tourmaline announced a major expansion on July 4, 2013 to its Peace River

High and Spirit River Charlie Lake play that is situated very close to Artek’s

Mulligan area lands. Tourmaline is in the process of delineating various

structural oil and gas pools having drilled 43 Charlie Lake oil wells along this

trend since 2011 with 100% success rates. It appears industry is developing

this at four to six wells per section suggesting between 120 and 180 possible

locations. No PUD’s from here have were recorded in the Dec. 31, 2012

Sproule reserve report. The average 2P reserves per well is ~300 to 500

mboe and Tourmaline plans to drill up to 75 wells into 2014.

Artek drilled its first exploration well at Mulligan and we expect management

to possibly drill a second well before the end of 2013 where it will test up to

five target formations. The first exploration well tested 650 boe/d with liquids

yield of 40 bbls/mmcf that is water driven. Management’s strategy is to grow

oil production by locating and drilling vertical discovery wells into these

trapped reservoirs with subsequent horizontal leg extensions to extract more

production quickly at an all-in cost of ~$4 million per well. Production from

this tight deposit is stimulated using multi-stage fracturing technology.

In 2011 at Dunvegan, management tested production at 421 boe/d (50% oil)

with an IP30 rate of 150 boe/d (50% oil) resulting from a nine-stage frac.

These wells produce with a 90% water cut that flows to a nearby 5,000 bw/d



water disposal facility. The water comes from a natural aquifer situated above

the reservoir. Further exploration work at Dunvegan has been postponed and

is not the current focus.

Leduc/Woodbend property, Central Alberta The Leduc Woodbend property is located just south of Edmonton, Alberta,

and acts as a natural physical hedge to oil without having to enter into a

financial contract. Reliable production comes from two Glauconitic sandstone

oil pools. The first pool flows light to medium gravity oil under water flood at

annual declines of 9%. Artek assumed operatorship from Apache this past

year and still holds a 40% W.I. in this unitized pool. The second pool

represents a 67% non-unitized W.I. that currently has two producing wells.

This old Encana light oil asset was obtained via the company’s Nov. 2009

acquisition of Rising Sky Energy Ltd. for $23.8 million, which at that time

produced ~400 bbls/d. Over the next two years management spent another

$2 million drilling one well and introducing various water flood schemes,

which increased net production to 600 bbls/d. in 2011, the Leduc property

generated approximately $17 million of annual operating cash flow before

the company sold a third of its W.I. (218 bbls/d oil) on Jan. 4, 2012 for $19.4

million ($89,000/boepd; $30/boe on 2P basis). The sale dropped the net

production volumes back to 440 boe/d (94% oil), which is what it produced

when the asset was first purchased. After drilling 4 (1.6 net) wells in the fall of

2012, field estimates were back up to 670 boe/d (87% oil). Artek took over

operatorship from Apache in 2012 enabling it to control when and how

quickly these wells are drilled. As a result, management was able to

successfully drill another 3 (1.2 net) Leduc wells while it completed two work

overs in Q1/2013 causing flush production volumes to peak at a record 700

boe/d (96% oil).

First year production typically declines at ~25%, and each well costs

$850,000 gross all in. The wells produce at 45% water cuts, and the

associated handling causes slightly higher operating costs. At current oil

prices, this property still produces very attractive economics with NPV (10%, bt)

of ~ $4 million per well.

Other Deep Basin Assets, British Columbia/Alberta Artek’s Deep Basin property straddles the B.C./Alberta border where it has

accumulated 82 net sections in four properties: Tupper, Noel, Elmworth and

Sinclair. The Deep Basin is primarily a natural gas and liquids producing

region. Artek’s largest property is Noel with 33 net sections 77% W.I. situated



southwest of the town of Dawson Creek, B.C. Noel targets multi-zone

Cadomin and Nakanassin Formations (250 meter play thickness) at a depth

of 3,200 meters, as currently explored by EnCana, ConocoPhillips and

Daylight Energy. These are low cost ($7/boe) and high-impact plays chasing

deep natural gas reserves with high reservoir pressures. These well-

established long life dry gas wells decline at about 15% and produce for over

six years. No exploration or development activities are scheduled for Noel in

the near term.

Similarly, all exploration and development activities have been suspended at

the company’s Sinclair/Glacier property, where Artek has been targeting the

Upper Montney formation that offset its Q4/2010 discovery well. The

discovery well tested at 8 mmcf/d, was brought on stream at 5mmcf/d and

declined to 3mmcf/d at IP180, but has been shut in since June 2011. The

Montney formation at Sinclair can be developed at three wells per section in

both the Upper and Lower Montney. Artek has a 50/50% W.I. with Devon

Energy Corp. (DVN-NYSE) and a three to six-year time line to explore and

subsequently delineate this play.

Forecast In the near-term, we see management focused on initiatives that make Artek

more attractive for a potential sale transaction. Instead of continuing to

develop the Doig play, management intends to deploy capital in a more

balanced approach: proving up and de-risking two additional Triassic plays,

developing both its light oil cash cow property at Leduc/Woodbend as

required, and delineating further the Doig condensate pool north towards its

Fireweed acreage.

In 2012 and 2013, management was primarily focused on de-risking and

extending the Doig play through a combination of exploration and delineation

drilling, thereby proving a type curve that exceeds what Sproule granted in its

Dec. 31, 2011 reserve report. Both production and reserve growth and its

objective to increase its liquid content from 10% in 2009 to ~40% was driven

by successfully drilling seven (60% W.I.) wells in 2012 at 100% success rate.

We remind readers that it took up to six gross wells before management

figured out the optimal way to stimulate and complete a Doig well (i.e. 15

stage propane frac).

Since then, management conservatively has identified ~74 (43 net) drilling

locations, and Exhibit 6 below illustrates the type of scalable production



growth the Doig condensate play could generate if it committed $132 million

in capital to drill 23.4 net wells (60% W.I) over a five year period. However,

we do not expect the Doig play to be the main driver in 2014 as management

wants to leave some “meat on the bones”. We are of the viewpoint that the

Doig wells will generally only be drilled to replace declines or delineate and

extend the pool.

Exhibit 6: Sample repeatable drilling program at Inga assuming 7 net wells per year


Given the aforementioned, we expect that the majority of 2014 will be

allocated to further proving up the Montney by fine tuning its drilling and

completions method (possibly large stage slick water fracs) in order to de-risk

and a generate a rewarding type curve.

2014E Capex Our projected 2014 capex program outlines management’s intention to

continue to focus the majority of its near-term drilling efforts on unlocking

liquids rich natural gas and light oil in tight sand formations characterized by

good porosity with lower permeability that can be recovered and stimulated

using a multi stage hydrocarbon fracturing program. We project the company

spending $57.8 million on its 2014 capex program, drilling up to 17 (9.8 net)

wells versus 16 (9.5 net) in 2013. As illustrated in Exhibit 7 below, we project

management to allocate its upcoming exploratory budget to be released by

February 2014 to 6 (3.2 net) wells targeting the Montney formation; 5 (3 net)



Doig wells; 2 (2 net) PRA wells at its Mulligan property; and 4 (1.6 net) light

oil wells at its Leduc/Woodbend property. It is vital that management

continues to drill these Glauconitic wells given that this property generates

between $8 and $12 million in annual cash flow pending the oil price. These

wells generate ~$50/boe operating netbacks (94% light oil) at CDN$95 to

$100/bbl realized oil prices.

Exhibit 7: Capex history and forecast from 2012A to 2014E


Infrastructure, land and seismic

In our projected 2014 capex program, approximately $3 million has been

allocated to land acquisitions and seismic. Given that the Doig and Montney

are both geophysical driven plays, funds need to be spent on seismic in order

to locate and identify the lucrative sand bar trends.

In 2013, Artek invested $5 million ($3 million net) on expanding its Inga

production facility in order to increase the processing capacity from 17 to 28

mmcf/d. This expenditure will increase the liquids recovery before the LRNG

flows to a third party deep cut facility. The company also acquired

operatorship in a 16 mmcf/d compression and dehydration facility with ~25

km of tie-in pipelines from the Pengrowth acquisition in August 2013.

We project the company will spend ~$4 million on tie-in pipelines and

necessary facilities pertaining to its Montney drilling program. Artek is not

Capex Program ($000) 2013E

Drilling & Completions

Facilit ies & Equipoment

Land and Seismic

Capitalized Overhead

Workover & Other

Total F&D

Acquisition & Disposal of Property

Total FD&A

Property Well Summary Gross Net Gross Net Gross Net

Leduc Woodbend 4.0 1.6 3.0 1.2 4.0 1.6

Inga Fireweed 7.0 4.2 8.0 4.8 5.0 3.0

Montney - - 3.0 1.5 6.0 3.2

PRA 2.0 1.95 2.0 2.0 2.0 2.0

Deep Basin - - - - - -

Dry and Abandoned - - - - - -

Total Capex 13 7.8 16 9.5 17 9.8

-$19,444 $14,830 -

$40,498 $93,903 $57,840

$59,942 $79,073 $57,840

- $3,000

$174 - -

$652 - -$1,000

$7,003

2012A

$44,761 $79,073

2014E

- $4,000

$51,840

$7,352



required to spend an overabundance of capital to flow its production to

market as it is near existing infrastructure includes the Alaska highway

(access), two deep cut facilities at Stoddart and McMahon, and the Alliance

gas sales pipeline as shown in Exhibit 8 below. The company operates and

controls its tie-in facilities that include separators, dehydration, storage and

compressors facilities. Production is at risk to be shut-in from time to time due

to maintenance but having two separate deep cut facilities reduces its

dependency. The facilities have abundant capacity as it flows ~7 mmcf/d to

McMahon gas processing facility where volumes flow to Spectra’s main line.

All surplus volumes flow to CNRL’s Stoddart facility that has 50 mmcf/d of

spare processing capacity.

Exhibit 8: Access to existing BC infrastructure

.


Production Summary and Forecast Artek grew production from nil at inception to current field estimate of ~4,800

to 5,000 boe/d (38% liquids) primarily through the drill bit. Its operations

team is astute, both in drilling and completing wells, and in field operations

having previously worked for major companies. Given that the company was

sitting on a several LRNG plays at Inga and Fireweed, management decided

in 2010 to alter its natural gas focus and increase the aggregate liquids

production weighting from 10% in 2009. Please note that the achieved liquids

rate of ~40% has been constant over the past few years, which is due to the

fact that new Doig wells, which represent the largest component of volume

adds per well on average IP30 of 1,000 to 1,200 boe/d, is weighted

~65%/34% to NG and liquids.



Our estimated average production for 2014 of 5,864 boe/d is derived by

incorporating production additions from a 17 (9.8 net) well drilling program.

This represents a year-over-year increase of 58% (3,690 boe/d) with a liquids

weighting of 41%. The slight increase in liquids from a 38% weighting at

2013E exit is driven by oilier production from its PRA wells at Mulligan drilling

program in 2014E, and the slightly higher condensate yield expected from its

LRNG plays at Inga/Foreweed.

Exhibit 9 below illustrates the corporate production history and percentage

growth from 2010 to 2014E, using an average corporate decline rate of 37%

over all existing production plus all new production additions resulting from

the 2014E drilling program. Our 2014E production estimates adds ~3,005

boe/d on an average base before declines. We do note that our daily

production per well is driven by the number of successful fractures executed

per well bore to stimulate flow from tight rock, and that the 6 (3.2 net)

Montney wells are still deemed exploratory in nature and thus carry a greater

than normal risk.

Exhibit 9: Production history and forecast from 2010A to 2014E


Production 2010A 2011A 2012A 2013E 2014E

Crude oil & Liquids (bbls/d) 584 996 1,106 1,416 2,431

Natural Gas (mcf/d) 7,342 8,193 9,968 13,643 20,598

Total Production (boe/d) 1,808 2,362 2,768 3,690 5,864

Oil & Liquids Weighting 32% 42% 40% 38% 41%

20%

30%

40%

50%

60%

70%

80%

90%

-

2

3

5

2010A 2011A 2012A 2013E 2014E

(000s)

Total Production (boe/d)

Oil & Liquids Weighting



Well Economics

Below we discuss the economics of the four well types that management is

currently drilling: Doig and Montney at Inga/Fireweed, Glauconitic wells at

Leduc/Woodbend, and Charlie Lake at Mulligan.

Doig well The gross cost to drill, complete and tie-in one Inga well appears to be

approximately $7.5 million depending on the number of fracs used (assume

12+ fracs per well). In our NPV calculation, we assume $7.5 million given the

company’s strategy to drill mono-bore wells and use a minimum 12-stage

frac completion on a go-forward basis. A typical Doig well should recover a

minimum 550Mboe of reserves, of which 200Mboe are in the form of liquids

(64/36 gas to liquids). Using an average first-year production rate 332 boe/d

with an 18% annual decline thereafter, generates an estimated NPV (10%, bt)

of ~$6.15 million per well (~1.2 year payout) by applying a blended

operating netback of $32.75/boe. Management has proven that full payout

can be achieved more quickly (best well repaid within 6.5 months) by

increasing the number of frac stages to 15.

A recent 15-stage fractured Doig well yielded first year cash flow of ~$4.6

million, and is on pace to generate ~$20.9 million over its well-life, before

deducting out cost recovery. It appears that increasing the number of frac

stages from 6 to 15 per well is increasing both the first year average

production rate to 974 boe/d (from 332 boe/d), and the potential EUR to as

much as 800Mboe per well. There appears to be a high variance in the

estimated EUR per well that ranges between 400 and 800Mboe, with Sproule

assigning 550Mboe.

Exhibit 10: Key corporate type curves




Montney well Although little economic well data is known with respect to the prospective

Montney play at Inga/Fireweed, we have assumed a gross cost to drill,

complete and tie-in one Montney well of $7 million using a 20-stage water

based completion program. We expect a production profile of 60/40 natural

gas to liquids, of which 20% is categorized as condensate. With an estimated

EUR of 583Mboe per well, an IP30 of 640 boe/d declining at a first year rate

of ~65% would suggest a first year average production rate of 337 boe/d.

Declining the IP360 of 220 boe/d at 15% annually thereafter and applying an

operating netback of $32/boe, produces a NPV (10%, bt) of ~$4 million per

well.

This is still an early stage play that is just progressing beyond the land

assembly phase and as such, the cost structure still needs to be defined. We

note that management will need to reduce both its drilling and completion

costs, settle on an optimal completion method, and firm up the initially

attractive 40% liquids content (20% of which is C5+) in order to improve both

the operating netback and resulting NPV values.

Charlie Lake well (PRA at Mulligan) We assume an all-in cost $4 million for a Charlie Lake well at Mulligan (PRA),

which Artek is drilling at 100% W.I. Tourmaline (TOU-T) is currently drilling

and completing similar wells in the immediate vicinity for ~$3.6 million.

Applying Tourmaline’s well results, we assume an EUR per well of 350Mboe,

an IP30 of 565 boe/d declining at a first year rate of 65% to generate a first

year average production rate of ~345 boe/d. Declining the IP360 of 342

boe/d at 15% and applying a $48.73 operating netback generates an NPV

(0%, bt) of ~$5.8 million per well.

Glauconitic well The gross cost to drill these oil wells is $850,000.. Estimated recoverability per

well is approximately 140Mboe and these wells tend to flow at an IP30 rate of

140 bbls/d. Applying a 25% decline rate, the estimated NPV (10%, bt) over

the reserve life index of approximately 5.07 years is ~$4.3 million. It should

be noted that the current water flood recovery has flattened the annual

production decline to 9% given that the production of the older wells is further

down the type curve (reserve tail). Given all of the recent new drills in our

production profile, we have maintained our 25% decline for the purpose of

calculating our well economics.



Key Risks Investing in junior domestic oil and gas producers carries with it greater than

average risk given all of the risk factors outlined below.

Exploration and Production Risks – Exploration for oil and natural gas involves

a high degree of risk and there can be no assurance that there will be new

commercial discoveries. Future exploration may involve unprofitable efforts

from dry wells and from wells that are productive but do not produce sufficient

revenues to return a profit after drilling, operating and other costs. Some

external factors such as weather conditions or technical failures could result

into unexpected business interruptions and monetary losses. Oil and gas

exploration carries with it the potential for failure despite the expertise and

proven technology relied upon today. It is possible to drill dry, or uneconomic,

wells. In the current situation where the company is de-risking several LRNG

plays, management is risking $7+ million per well to validate its play concept.

This is a high cost well for a company of Artek’s market cap. This is one

reason why management brought in Kelt as 40% to 50% W.I. partner in the

Doig/Montney assets, respectively, to share in the risk. Although our forecast

assumes that management will drill successful wells, and we have risked these

wells between 75% and 100% there is no assurance this occur.

Execution Risk - Although part of our investment thesis supports potential for

share price appreciation driven by a sales event or merger, there is a

possibility that neither of these event may occur. This however, has been

management’s exit strategy and they have played integral roles in the success

of building and selling E&P companies in the past. We remind the reader that

past performance is not indicative of future execution.

Commodity Prices – Oil and natural gas prices are determined based on both

global and domestic demand, supply and other factors, including geo-

political events, all of which are beyond the control of the Company. If world

oil prices and domestic natural gas prices were to decline, certain wells or

other projects may become uneconomic leading to a reduction in the future

volume of the Company’s production. Artek could also decide not to produce

from certain wells at lower prices. All of these factors could result in a material

decrease in Artek’s future net production revenue, potentially causing a

reduction in exploration, development and acquisition activities.

Reserves, Resource Estimates and Production Risks – There are a number of

uncertainties inherent in estimating quantities of oil and natural gas reserves

and the future cash flows attributed to such reserves. Estimates of



economically recoverable oil and natural gas reserves and the resulting future

net revenues are all based on a number of variable factors and assumptions

which may vary materially from actual results. Reserves may be subject to

upward or downward revision based on production history, exploration and

development results, commodity prices, royalty rates, expected capital

expenditures, future operating costs, government regulations and other

factors. Upward or downward revisions are often required due to changes in

well performance, prices, economic conditions, and governmental restrictions.

Furthermore, the Company’s actual crude oil and natural gas reserves and

production, and therefore its operating cash flows and results of operations,

will vary from estimates and such variations could be material.

Financing Risks – Exploring and developing for prospectus hydrocarbons

requires a combination of debt and equity capital. We have assumed normal

market conditions will prevail during our time-line cited in this report.

However, we remind the reader that there is no certainty that Artek can raise

capital when required, which would have negative implications on our

projections. Moreover, any additional equity financing will be dilutive the

common shareholders and any debt financing may restrict future financings

and operating activities.

Other Potential Key Risks – Future Development Costs and Reserves;

Exploration, Production and General Operational Risks; Competitive

Conditions; Availability of Equipment and Access Restrictions; Reliance on

Third Party Contractors; Third Party Agreements and Authorizations; Reserves

Depletion; Production; Oil and Gas Prices and Marketability; Delays in

Production, Marketing and Transportation; Environmental Protection;

Unconventional Oil and Gas Resources and Hydraulic Fracturing; Title;

Governmental Regulations; Foreign Operations and Enforcement of Laws;

Third Party Credit Risk; Hedging Activities; Fiscal Matters; Costs of New

Technologies; Uninsured Risks; Decommissioning Costs; Labour; Reliance on

Third Party Operators and Key Personnel; Global Financial Crisis; Volatility of

Market Price of Common Shares; Litigation; Potential Dilution; Conflicts of

Interest; Write-downs of Impairments and other risks.



Valuation We are initiating coverage on Artek Exploration with a BUY recommendation

and a 12-month price target of $4.30 based on applying 2014E multiples of

6.9x EV/DACF and $61,000/boepd. Artek currently trades at 5.1x EV/DACF

and $53,000/boepd multiples based on our 2014E estimates. This compares

to ~$67,000/boepd based on 2014E consensus estimates from our selected

peers.

Comparison Approach We have chosen to compare Artek to its two closest peers, Kelt Resources Ltd.

(KEL-T, not rated) and Storm Resources Ltd. (SRX-V, not rated). These three

companies are most similar when comparing production weighting with the

majority of the near-term production and cash flow growth coming from

developing their respective Montney resource plays in NEBC. Kelt currently

holds the other ~40% W.I. in Artek’s Triassic LRNG plays at Inga/Fireweed,

while Storm is actively de-risking ~112 net sections of Montney rights at

Umback, which is situated directly to the northeast of Fireweed.

Kelt Resources Ltd:

Kelt was spun out in February 27, 2012 as part of the plan of arrangement

between ExxonMobil and Celtic Exploration led by David Wilson and members

of Celtic’s management team. This successful management team decided to

keep Celtic’s W.I. in a pure NG play at Grande Cache, Alberta, an early

stage light oil Montney exploration prospect at Karr, Alberta, plus its ~40%

non-operated W.I. in the two LRNG resource plays at Inga/Fireweed that it

shares with Artek.

The company recently closed (Dec. 2013) on an acquisition of light oil and

natural gas assets at Spirit River and Pouce Coup, respectively, in the PRA

area of west central Alberta that is in close proximity to its pre-existing

properties. This ~$192 million acquisition significantly increased Kelt’s 2014E

guidance to 10,500 boe/d (70% natural gas) from 5,850 boe/d (78% natural

gas) previously. Consensus estimates project 2014E production to average

between 10,000 and 11,000 boe/d (~70% to NG) versus our estimate for

Artek of 5,864 boe/d (50% NG).

Storm Resources Ltd:

Similarly, Storm is also focusing much its production growth on the LRNG

Montney play at nearby Umbach in NEBC that is situated just north of

Inga/Fireweed. The Montney at Umbach also appears more weighted to

natural gas with IP90 liquids yield of 53 bbls/mmcf (56% condensate)



compared to early IP30 Montney liquids yield booked by Artek at

Inga/Fireweed between 114 to 124 bbls/mmcf (78% to 82% condensate).

No further capex dollars have been committed to the company’s other key

P&NG assets comprised of a pure natural gas play that targets the Muskwa

formation (335 boe/d at Q3/2013) in the Horn River Basin (HRB), in NEBC;

and its Grande Prairie area asset (1,295 boe/d at Q3/2013) of corporate

production.

Artek Compared to Kelt and Storm.

Comparatively, Artek’s production growth is similar to its immediate peers or

slightly exceeding the group average as tabled below. The major difference is

Artek’s 2014E production profile with its 59% weighting to natural gas versus

70% and 79% for Kelt and Strom, respectively. At current commodity prices,

Artek’s higher weighting to liquids should generate slightly better operating

netbacks, which should lead to stronger recycle ratios than the immediate two

peer companies.

Exhibit 10: Comparative valuations of selected peers

Source: Bloomberg, Factset and Company Reports

Kelt currently has an implied valuation for 2014E of ~$90,000/boepd based

on consensus estimates despite its average 70% natural gas weighting. We

conclude that a substantial management premium has been bestowed, given

their recent success in selling Celtic to ExxonMobil.

Storm has an implied value of $69,000/boepd based on 2014E consensus

estimates with a production profile that is weighted 79% to natural gas.

Artek has an implied value of $53,000/boe/d based on 2014E estimates.

Comparatively, on an EV/boepd basis, Artek is currently trading at ~0.6x Kelt,

and ~0.78x Storm’s valuation. Artek also has more near-term cash flow

diversity as ~$10.5 million of the annual projected cash flow is spun off its

light oil play at Leduc Woodbend.

Consensus

Avg. Production Consensus

Select Companies 2014E 2014E 2014E

% Gas (boe/d) EV/boepd

Kelt Exploration (KEL) 70% 10,500 $90,000

Storm Resources (SRX) 79% 5,900 $69,000

Artek Exploration (RTK) 59% 5,869 $54,000

Peer Group Average 70% 6,942 $67,000



We contend that the difference in valuation should narrow between Artek and

its immediate peers in part by an appreciation in Artek’s share price. Near

term catalysts that should drive this share price appreciation should come

after management (i) proves that the LRNG play runs through its 120 (71 net)

sections of Montney rights in NEBC; (ii) further delineates and extends the

boundaries of its Doig condensate pools at Inga and Fireweed; and (iii)

proves up its new oil discovery at Mulligan, in the PRA area of west central

Alberta. We are confident that management will execute on the foregoing.

Artek is also trading at 24% discount to its Dec. 31, 2012 net asset value of

$4.51 per share before considering the addition value created in 2013. The

backward looking NAV of $4.51 per share ($4.40 per share in 2011) was

calculated using the NPV (10%, bt) of the 2P reserves of $257.36 million, plus

$35.6 million in land (independent evaluated by Seaton-Jordan & Associates

Ltd.), plus $7 million in proceeds of dilutive stock options, less $48.897

million in working capital deficit as at FYE 2012.

Recommendation We view the risk-reward to investors at the current valuation is compelling and

still offers the potential for share price appreciation as Artek continues to drill,

frac and test the Montney resource play and prove up the 120 (71 net)

sections that it holds together with Kelt Resources. Although Artek shares are

up ~26% from the 52 week low, we believe there is still substantial share

price potential in the mid-term given the following:

positive condensate price outlook that dominates its two condensate rich

LRNG plays at Inga/Fireweed;

prove that the Montney resource play runs through its Inga/Fireweed lands

while lowering the all-in costs below $7 to $8 million that management

achieved on the first several wells;

de-risk its new discovery at Mulligan (PRA) that targets several prospective

sub-cropping oil plays where Artek holds 32 (30 net) sections on trend,

and industry is de-risking at four to six wells per section adding up to 180

new drilling locations;

continue to de-lineate and extend the condensate rich Doig pool and

replace declines through low risk in-fill drilling; and

proven management team with history of building and selling oil and gas

companies.



In addition, we believe that Artek is either (i) a takeover candidate with target

assets conveniently sitting between several majors that are actively drilling in

the immediate vicinity, or (ii) a potential merger candidate with Kelt. Artek ‘s

management team has a demonstrated history of starting and selling

companies having played an integral role in growing production of Ketch

Resources Ltd. From 1,600 to 10,000 boe/d, which it then sold to Ketch

Resources Trust (Advantage Energy Income Fund) in 2002 for ~$500 million.

From a mergers perspective, we see Kelt as the most likely merger candidate

given its assets overlap and provide many synergies that can enhance its

valuation further from Kelt’s existing management team. In order for a merger

to occur, the valuation gap between Artek and Kelt will need to close.

Artek may also be attractive to several of the larger companies that are

actively drilling in the immediate area. Petronas/Progress, Shell, Tourmaline

and Bonavista all have very significant capex budget allocated to de-risking

the Montney resource play in NEBC. Acquiring Artek with its 60% operated

W.I. in a large land position (61 and 71 net sections of Doig and Montney

rights, respectively) is also very compelling to these larger E&P companies

ahead of the five tabled west coast LNG facilities.



Appendix A – Management and Directors Exhibit 12: Artek Exploration – Management Team and Board of Directors


Darryl MetcalfePresident and

CEO

Mr. Metcalf has been president, chief executive officer and director of Artek since 2005. Prior thereto, he served

as vice-president, exploration & development of Ketch Resources Ltd. and director, Northern Business Unit of

Ketch Energy Ltd.

Darcy Anderson

Vice-President,

Finance and

CFO

Mr. Anderson joined Artek in September 2009 as vice-president, finance & chief financial officer. Prior thereto, he

was vice-president, finance & chief financial officer of Pegasus Oil & Gas Inc. and Mustang Resources Ltd.

Greg Frolek

Vice-President,

Business

Development

Mr. Frolek has served as vice-president, business development of Artek since 2005. Prior thereto, he was a senior

engineer with Ketch Resources Ltd. and Ketch Energy Ltd.

Peter Andrews,

Vice-President,

Drilling &

Operations

Since joining Artek in 2005, Mr. Andrews has served as vice-president, drilling & operations. Prior thereto, he was

manager, drilling & operations and senior production/completions engineer of Ketch Resources Ltd.

Bruce NociarVice-President,

Production

Mr. Nociar joined Artek in 2008 and currently serves as vice-president, production. Prior thereto, he was

manager, engineering of Kereco Energy Ltd. and senior exploitation engineer of Ketch Resources Ltd.

Jennifer SwertzVice-President,

Land

Ms. Swertz has been vice-president, land of Artek since 2005. Prior thereto, she was vice-president, land as well

as manager, land, at Galleon Energy Inc.

Anthony SacheliVice-President,

Exploration

Mr. Sacheli joined Artek in 2005 and currently serves as vice-president, exploration. Prior thereto, he was

manager, Northern Alberta Business Unit of PrimeWest Energy Ltd.

Michael SandrelliCorporate

Secretary

Mr. Sandrelli has been corporate secretary for Artek since 2005.

Mr. Sandrelli has been a partner at Burnet, Duckworth & Palmer LLP since 2004.

M. Bruce Chernoff Chairman

Mr. Chernoff co-founded Pacalta Resources Ltd., a public junior oil and natural gas company with operations

in Canada and Latin America, where he held various senior positions including executive vice president and

chief financial officer. Mr. Chernoff was a director of Pacalta from 1992 until it was purchased for $1 billion by

Alberta Energy Company in May 1999. Mr. Chernoff is currently president of Caribou Capital Corp. and is also a

director of several other public companies (Maxim Power, Calmena Energy Services). In June 2002, Mr. Chernoff

initiated the formation of Harvest Energy Trust to pursue oil and natural gas development and acquisition

opportunities. He holds the position of chairman of the board. Mr. Chernoff holds a Bachelor of Applied Science

in Chemical Engineering from Queen’s University.

Gary F. Aitken Director

Mr. Aitken has been the president of Whitemountain Resource Properties Ltd. since March 2005. Mr. Aitken

served as consultant of NCE Diversified Flow-Through (07-2) Limited Partnership. He served as land and financial

consultant of NCE Diversified Management (04) Corp., a general partner of NCE Diversified Flow-through (04)

Limited Partnership and served as senior land specialist. Mr. Aitken served as land and financial consultant of

Strategic Energy Management Corp., manager of Sentry Select Energy Income Fund (also known as Strategic

Energy Fund). He has been employed in the oil and gas industry as a professional land negotiator and energy

investment advisor, most recently with NCE Resources Group, now Petrofund Energy Trust. Mr. Aitken served as

land and financial consultant of Sentry Select Capital Corp. since 2002. He served as an executive vice

president of Precept Resource Management Corp. since 2005. He also served as the president and founder of

Judelle Resources Inc., and Chowade Energy Inc., both private oil and gas companies. Mr. Aitken served as the

chairman of Fairquest Energy Ltd. and served as its independent director since May 20, 2005. He serves as

director of Advantage Oil & Gas Ltd. He has been a director at Artek Exploration Ltd. since March 2005. He

serves as a director of Canadian Petroleum Insurance Exchange, JB Oil and Gas Insurance Ltd and is an active

member of the Canadian Association of Petroleum Landmen. Mr. Aitken served as director of Fairborne Energy

Trust (now Fairborne Energy Ltd.) since May 31, 2002. He served as director of Precept Resource Management

Corp. since 2005. Mr. Aitken received a Bachelor of Commerce Degree in Accounting and Finance from the

University of Alberta.

Rafi G. Tahmazian Director

Mr. Tahmazian has over 20 years of experience in the energy sector and financial services industry. He is currently

a managing director of Canoe Financial LP and holds positions as both director and an advisory board

member of several private resource entities and energy specific investment funds. From 1996 to 2008, he was a

partner at FirstEnergy Capital Corp., a leading investment dealer that focuses on the energy industry. His final

role prior to leaving FirstEnergy was as vice chairman and managing director. From 1993 to 1996, he worked

with First Marathon Securities and from 1989 to 1993 he was assistant treasurer of LL & E Canada. Mr. Tahmazian

holds a Bachelor of Economics from the University of Calgary.

David J. Wilson Director

Mr. Wilson is currently president, CEO and a director of Kelt Exploration, a spinout company of Celtic

Exploration Ltd. where he held the position president and chief executive officer since September 30, 2002, and

director since September 2002. Prior to that, Mr. Wilson served as president of Vintage Petroleum Canada, Inc.

from May 2001 to May 2002 and president and chief executive officer of Genesis Exploration Ltd. from 1992 to

May 2001.

Management Team

Board of Directors



Appendix B – Historical and Projected Financial

Statement

Netback Summary (boe) 2010A 2011A 2012A 2013E 2014E

Revenue $42.91 $52.67 $40.06 $43.54 $45.39

Royalty per boe -$7.02 -$10.14 -$7.29 -$7.88 -$6.15

Operating Costs per boe -$12.62 -$11.61 -$10.13 -$10.16 -$10.91

Transportation per boe -$1.77 -$1.79 -$1.65 -$1.63 -$0.90

Operating Netback ($/boe) $21.50 $29.14 $21.00 $23.87 $27.44

G&A -$3.73 -$3.36 -$3.12 -$2.73 -$3.35

Interest per boe -$2.95 -$2.05 -$1.43 -$0.74 -$0.42

Cash Netback ($/boe) $14.37 $23.73 $16.46 $20.40 $23.66



Artek Exploration Ltd. Financial Summary

All amounts in CDN 2011A 2012A 2013E 2014E

Production

Light Oil (bbl/d) 879 881 1,066 1,292

Natural Gas (mcf/d) 8,193 9,968 13,643 20,598

NGL (boe/d) 85 226 351 1,138

Total Avg (boe/day) 2,362 2,768 3,690 5,864

Income Statement (000)

Revenue $44,279 $41,105 $58,587 $97,029

Expenses $61,194 $43,277 $42,694 $71,168

Net Earnings ($16,915) ($2,172) $2,706 $13,022

Cash Flow Statement (000)

Operating $21,666 $15,667 $26,992 $50,639

Financing $26,395 $12,644 $78,572 ($931)

Investing ($48,061) ($28,311) ($95,415) ($57,840)

Changes in Cash & Cash Equivalents $0 $0 $10,148 ($8,133)

CFPS - Fully Diluted $0.53 $0.37 $0.40 $0.70

Balance Sheet (000)

Current Assets $20,474 $10,795 $15,207 $25,323

Property and Equipment $133,886 $150,887 $222,185 $242,726

Other $13,476 $18,267 $21,714 $21,714

Total Assets $167,836 $179,949 $259,105.96 $289,762.86

Current Liabilities $67,940 $59,691 $80,898 $98,025

Long-term Liabilities $5,768 $5,587 $6,222 $6,222

Shareholders' Equity $94,128 $115,189 $171,985 $185,515

Total Liabilities and Equity $167,836 $180,467 $259,106 $289,763

Beacon Securities Ltd.| 66 Wellington Street West, Suite 4050, Toronto, Ontario, M5K 1H1 |416.643.3830 |www.beaconsecurities.ca

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As at

December 31, 2013

BUY 20 59%

Speculative Buy 5 15% SPECULATIVE BUY

HOLD 3 9%

SELL 1 3%

Restricted 0 0%

Under Review 5 15%

Total 34 100%

# Stocks Distribution

SELL

HOLD

BUY

Total 12-month return expected to be negative

Total 12-month return expected to be between 0% and 15%

Total 12-month return expected to be >15%

Potential total 12-month return is high (>15%) but given elevated risk, investment could result in a material loss

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