Artek Announces Year End 2013 Financial and Operating Results

Artek Exploration Ltd. ("Artek" or the "Company") (TSX:RTK) is pleased to
provide this summary of its financial and operating results for the three months
and year ended December 31, 2013. A complete copy of the Company's audited
comparative financial statements for the years ended December 31, 2013 and 2012,
along with management's discussion and analysis in respect thereof will be filed
on SEDAR at www.sedar.com and on the Company's website at
www.artekexploration.com.




                                      Three Months Ended     Years Ended    
                                         December 31,        December 31,   
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                                          2013       2012      2013    2012 
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(000s, except per share amounts)            ($)        ($)       ($)     ($)
Financial                                                                   
Oil and gas revenues                    14,913     13,494    57,678  41,105 
Funds flow from operations (1)           6,422      6,695    25,839  16,674 
  Per share - basic                       0.10       0.14      0.43    0.37 
            - diluted                     0.10       0.13      0.42    0.37 
Cash from operating activities          10,389      6,276    27,318  15,667 
Net earnings (loss)                       (140)    (9,868)    3,271  (2,172)
  Per share - basic                       0.00      (0.20)     0.05   (0.05)
            - diluted                     0.00      (0.20)     0.05   (0.05)
Capital expenditures                    21,995     17,809    98,748  59,942 
Property dispositions                        -         --         -  19,444 
Net debt (at period end) (2)           (68,451)   (48,913)  (68,451)(48,913)
Shareholders' equity                   169,000    115,189   169,000 115,189 
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(000s)                                      (#)        (#)       (#)     (#)
Share Data                                                                  
At period-end                                                               
  Basic                                 66,942     51,621    66,942  51,621 
  Options                                4,868      3,986     4,868   3,986 
Weighted average                                                            
  Basic                                 64,129     48,876    60,252  44,808 
  Diluted                               65,945     50,123    62,013  45,461 
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Operating                                                                   
Production                                                                  
  Natural gas (mcf/d)                   15,972     11,153    13,940   9,970 
  Crude oil (bbls/d)                       884      1,059     1,004     881 
  NGLs (bbls/d)                            480        421       370     226 
  Total (boe/d)(3)                       4,025      3,339     3,697   2,768 
Average wellhead prices (4)                                                 
  Natural gas ($/mcf)                     4.10       3.61      3.73    2.67 
  Crude oil ($/bbl)                      79.41      82.35     85.09   80.78 
  NGLs ($/bbl)                           54.37      42.87     51.93   52.50 
  Total ($/boe)(5)                       40.10      44.12     42.45   40.06 
Royalties ($/boe)                        (6.15)     (7.70)    (7.52)  (7.28)
Operating cost ($/boe)                  (11.35)     (9.25)   (10.59) (10.13)
Transportation cost ($/boe)              (2.13)     (1.69)    (1.97)  (1.65)
Operating netback ($/boe)(6)             20.47      25.47     22.38   21.00 
                                                                            
Wells drilled - gross (net)                                                 
  Development                           1 (0.6)    2 (1.0)  10 (5.8) 9 (5.4)
  Exploration                           2 (1.2)    1 (0.6)   6 (4.0) 4 (2.4)
  Abandoned                                  -          -         -       - 
  Total                                 3 (1.8)    3 (1.6)  16 (9.8)13 (7.8)
                                                                            
Undeveloped land                                                            
  Gross (acres)                                             236,315 169,740 
  Net (acres)                                               164,698 120,846 
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(1) Funds flow from operations is calculated using cash from operating      
 activities, as presented in the statement of cash flows, before changes in 
 non-cash working capital and settlement of decommissioning costs. Funds    
 flow from operations is used to analyze the Company's operating performance
 and leverage. Funds flow from operations does not have a standardized      
 measure prescribed by International Financial Reporting Standards ("IFRS") 
 and therefore may not be comparable with the calculations of similar       
 measures for other companies.                                              
(2) Current assets less current liabilities excluding fair value of         
 derivative instruments.                                                    
(3) For a description of the boe conversion ratio, refer to the advisories  
 contained herein.                                                          
(4) Product prices include realized gains or losses from financial          
 derivative contracts.                                                      
(5) Oil equivalent price includes minor sulphur sales revenue.              
(6) Operating netback equals petroleum and natural gas revenues including   
 realized hedging gains and losses on financial derivative instruments less 
 royalties, operating costs and transportation costs calculated on a boe    
 basis. Operating netback does not have a standardized measure prescribed by
 IFRS and therefore may not be comparable with the calculations of similar  
 measures for other companies.                                              



2013 FINANCIAL AND OPERATING HIGHLIGHTS



--  Increased annual average production to 3,697 boe/d, a gain of 34% over
    2012. Fourth quarter production rose to a new quarterly high of 4,025
    boe/d and was up 21% from the same period last year. 
    
--  Improved annual crude oil and liquids volumes 24% to 1,374 bbls/d, of
    which 73% was oil and condensate, representing 37% of total production
    for the year. 
    
--  Increased proved plus probable reserves 43% to 42.5 mmboe, highlighted
    by a 48% increase in proved plus probable crude oil and liquids reserves
    to 10.8 mmbbls, and grew proved reserves 25% to 21.4 mmboe. 
    
--  Replaced 2013 production of 1,349.5 mboe by 4.2 times and 10.6 times
    with proved and proved plus probable reserves additions, respectively. 
    
--  Invested $98.7 million in capital expenditures in 2013, including $14.3
    million on the Fireweed asset acquisition in northeastern British
    Columbia, $14.2 million on facility expansions and additions along with
    land and seismic in our core areas, and $59.4 million on drilling and
    completion activities, resulting in the successful drilling of 16 (9.8
    net) wells. 
    
--  Achieved all-in finding, development and acquisition ("FD&A") costs,
    including future development costs ("FDC"), of $14.84/boe on proved plus
    probable reserves and $27.39/boe on proved reserves. Finding and
    development costs were $15.68/boe on a proved plus probable basis,
    including FDC but excluding acquisitions and dispositions. 
    
--  Increased proved plus probable reserves value 52% to $392.3 million
    (before tax at 10% discount). 
    
--  Increased undeveloped land acreage 36% to 164,698 net acres. 
    
--  Improved year-end net asset value 20% to $5.43 per diluted share. 
    
--  Increased bank credit facility 38% during the year to $90.0 million. 



(i) More detailed information in respect of the results of Artek's independent
reserves evaluation for the year ended December 31, 2013 (the "Sproule Report")
as evaluated by Sproule Associates Limited ("Sproule"), capital efficiencies
including finding and development costs and finding, development and acquisition
costs and related information was contained in Artek's press release dated March
5, 2014 and will be contained in Artek's Annual Information Form to be filed on
SEDAR on or before March 31, 2014. It should not be assumed that the discounted
future net revenues estimated by Sproule represent the fair market value of the
reserves.


2013 FOURTH QUARTER FINANCIAL SUMMARY

Artek's average production for the three-month period ending December 31, 2013
was 4,025 boe/d (34% liquids), up 21% from 3,339 boe/d (44% liquids) recorded in
2012. Natural gas prices averaged $4.10/mcf up 14% from the previous year and
oil prices averaged $79.41/bbl down 4% from 2012. Fourth quarter funds flow
decreased 4% to $6.4 million from the same period of 2012 because of the drop in
liquids. As a result of curtailments associated with the expansion of third
party liquids infrastructure at Inga/Fireweed, Artek had to shut-in or restrict
production volumes in the area. This impacted production volumes during the
quarter, along with operational timing delays, by approximately 350 boe/d of
which approximately 150 bbl/d was liquids. These short-term events, as well as
decreased production volumes at Leduc Woodbend located in central Alberta,
resulted in lower liquids production and weighting for the quarter. The third
party curtailments at Inga also resulted in higher transportation costs to carry
the area's liquids to alternative locations. In addition, Artek incurred
significant third party water disposal costs associated with the Company's new
Charlie Lake oil play at Mulligan. Consequently, these events contributed to
increased operating and transportation costs, and therefore, a lower operating
netback of $20.47/bbl. The third party liquids infrastructure issues at Inga
have largely been alleviated going forward. Based on field estimates, Artek's
January 2014 operating netback was approximately $26.70/boe. In addition, the
Company has drilled water disposal wells at both Inga and Mulligan which are
expected to reduce operating costs even further commencing in the second
quarter. 


The Company invested approximately $22 million in the fourth quarter resulting
in the successful drilling of 3 (1.8 net) wells at Inga. Approximately $1.7
million was invested in facility additions or expansions and $0.60 million on
land expenditures at Mulligan and Inga. 


OPERATIONS UPDATE AND 2014 OUTLOOK

Artek previously announced a 2014 capital expenditure budget of $61 million to
$66 million, which contemplates the drilling of approximately 14 to 15 (9.1 to
9.7 net) wells. The program consists of up to 9 to 10 (5.3 to 5.9 net)
horizontal wells in the condensate rich Inga/Fireweed area (including 7 Doig and
up to 3 Montney wells), 3 (3.0 net) horizontal wells targeting Charlie Lake oil
in the Mulligan area of Alberta and 2 (0.8 net) vertical wells in the Leduc
Woodbend area of Alberta. The drilling program is weighted 100% towards projects
targeting oil and condensate, with associated natural gas. As a continuation of
its inventory and reserves growth strategy begun in 2013, the Company is
planning to allocate up to 50% of its capital investment towards validating
emerging growth plays in the Montney at Inga and the Charlie Lake oil play at
Mulligan as well as validating its pool extension in the Doig formation at Inga
South.  


Recently, Artek has completed and is currently flowing back its second
horizontal Doig well at Inga that was completed using a 24-stage slickwater
hybrid fracture stimulation treatment. In addition, the Company is drilling its
third horizontal Doig well in the Fireweed area with completion expected
following spring breakup. The Montney well that was completed this past January
and which recorded high liquids rates, remains shut-in due to high line
pressures relating to the recent new Doig wells brought on production. As a
result, Artek is using this opportunity to assess how the Montney well responds
to the shut-in or "soaking" time, a process that has yielded improved
performance from the Montney formation in other areas, as part of its long-term
Montney program evaluation.


On March 14, 2014, British Columbia announced the expansion of the Deep Well
Royalty Credit Program by extending royalty credits for all horizontal wells
with a vertical depth of less than 1,900 metres. Wells drilled on or after April
1, 2014 will benefit from these changes and will receive a royalty credit of
between $0.45 million and $2.8 million, depending on the total measured depth of
the well. In conjunction with this change, for wells that are eligible for this
expanded credit program, the minimum royalty payable will be 6%. These changes
are expected to have a positive economic effect on Artek's future wells drilled
in the Inga and Fireweed areas. 


In the Mulligan region, the Company is drilling its second 2014 horizontal
Charlie Lake well, which it also anticipates completing after spring breakup
with a minimum 20-stage fracture stimulation program.


At Leduc Woodbend, Artek has finished drilling two vertical development oil
wells that will be evaluated during the next several weeks and anticipates being
on-stream in April. The Company has also converted a well to a water injector
that is aimed at increasing water injection into the pool, which has been under
water flood since 2001, by approximately 21% to 25%.


Following spring breakup, the Company is planning to drill an additional seven
horizontal wells in the greater Inga/Fireweed area targeting natural gas and
condensate in the Doig and Montney formations, and an additional horizontal well
targeting the Charlie Lake formation in the Mulligan area.


Assuming the capital program is carried out as currently budgeted, 2014 average
production is forecast to be approximately 4,700 to 4,900 boe/d (38% to 39%
liquids) representing approximately 30% growth over Artek's 2013 average
production. Exit production is forecast to be approximately 5,200 to 5,300 boe/d
(40% liquids). Assuming 2014 commodity prices of $4.25/GJ AECO for natural gas
and US$95.00/bbl WTI for crude oil, the Company forecasts 2014 annual cash flow
of approximately $41 million to $43 million. In what can largely be described as
a value-driven or exploration year, the budget still forecasts year-over-year
production growth of approximately 30% and an increase in cash flow of over 50%.
Artek's budget is reviewed on an ongoing basis in the context of operational
results, commodity prices and the strength of its balance sheet. 


Artek has entered into several commodity contracts to protect its cash flow and
support its 2014 capital budget. The Company has entered into natural gas
production swaps on 10,000 mmbtu/d from April to October 2014 at an average
fixed price of $3.64/GJ. Also 400 bbls/d of crude oil production has been fixed
at an average price of CDN$100.75/bbl WTI for 2014. Lastly the AECO Basis on
2,000 mmbtu/d of natural gas has been fixed at 12.85% of Henry Hub for 2014.


NET ASSET VALUE

The following table provides management's calculation of Artek's estimated net
asset value at December 31, 2013 based on the estimated future net revenues
associated with Artek's proved plus probable reserves before income tax and
discounted at 10% as presented in the Sproule Report and an independent third
party evaluation of Artek's undeveloped land. 




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                                                              ($ thousands) 
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Proved plus probable reserves - discounted at 10% before tax                
 (note 1)                                                           392,345 
Undeveloped Land (note 2)                                            55,619 
Working capital deficiency as at December 31, 2013 (note 3)         (68,451)
Proceeds from dilutive stock options                                 10,322 
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Net asset value                                                     389,835 
                                                                            
Diluted Common shares outstanding (thousands)                        71,810 
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Net asset value per share                                              5.43 
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Notes:                                                                      
(1) Does not include any value for the March 14, 2014 amendment to the      
 British Columbia Deep Well Royalty Credit program.                         
(2) Based on an independent land evaluation provided by Seaton Jordan &     
 Associates Ltd. effective December 31, 2013, the details of which were     
 provided in Artek's March 5, 2014 press release.                           
 (3)  Working capital deficiency includes the Company's accounts receivable 
 and prepaid expenditures less accounts payable and accrued liabilities and 
 bank debt as at December 31, 2013.                                         



ADVISORIES

Forward Looking Statements: This press release contains forward-looking
statements. Management's assessment of future plans and operations and the
timing thereof, future results from operations, production estimates including
2014 average and exit production, commodity mix, initial production rates, the
Company's 2014 capital expenditure plans including the number and locations of
wells to be drilled, productive capacity of new wells, including the potential
of the Company's exploration wells at Inga and Mulligan, financial capacity to
carry out its planned 2014 capital program, commodity price forecasts and the
Company's estimated 2014 cash flow may constitute forward-looking statements
under applicable securities laws and necessarily involve risks including,
without limitation, risks associated with oil and gas exploration, development,
exploitation, production, marketing and transportation, loss of markets,
volatility of commodity prices, currency fluctuations, imprecision of reserve
estimates, environmental risks, competition from other producers, inability to
retain drilling rigs and other services, incorrect assessment of the value of
acquisitions, failure to realize the anticipated benefits of acquisitions, the
inability to fully realize the benefits of the acquisitions, delays resulting
from or inability to obtain required regulatory approvals and ability to access
sufficient capital from internal and external sources. As a consequence, the
Company's actual results may differ materially from those expressed in, or
implied by, the forward looking statements. Forward looking statements or
information are based on a number of factors and assumptions which have been
used to develop such statements and information but which may prove to be
incorrect. Although Artek believes that the expectations reflected in such
forward-looking statements or information are reasonable, undue reliance should
not be placed on forward looking statements because the Company can give no
assurance that such expectations will prove to be correct.


The recovery and reserve estimates of Artek's reserves provided herein are
estimates only and there is no guarantee that the estimated reserves will be
recovered. In addition to other factors and assumptions which may be identified
in this document and other documents filed by the Company, assumptions have been
made regarding, among other things: the impact of increasing competition; the
general stability of the economic and political environment in which Artek
operates; the ability of the Company to obtain qualified staff, equipment and
services in a timely and cost efficient manner; drilling results; the ability of
the operator of the projects which the Company has an interest in to operate the
field in a safe, efficient and effective manner; Artek's ability to obtain
financing on acceptable terms; field production rates and decline rates; the
ability to replace and expand oil and natural gas reserves through acquisition,
development or exploration; the timing and costs of pipeline, storage and
facility construction and expansion; the ability of the Company to secure
adequate product transportation; future oil and natural gas prices; currency,
exchange and interest rates; the regulatory framework regarding royalties, taxes
and environmental matters in the jurisdictions in which the Company operates;
and Artek's ability to successfully market its oil and natural gas products.
Readers are cautioned that the foregoing list of factors is not exhaustive.
Additional information on these and other factors that could affect the
Company's operations and financial results are included in reports on file with
Canadian securities regulatory authorities and may be accessed through the SEDAR
website (www.sedar.com) or at the Company's website (www.artekexploration.com).
Furthermore, the forward looking statements contained in this document are made
as at the date of this document and the Company does not undertake any
obligation to update publicly or to revise any of the included forward looking
statements, whether as a result of new information, future events or otherwise,
except as may be required by applicable securities laws.


BOE Conversions: Barrel of oil equivalent ("BOE") amounts may be misleading,
particularly if used in isolation. A BOE conversion ratio has been calculated
using a conversion rate of six thousand cubic feet of natural gas to one barrel.
This conversion ratio of six thousand cubic feet of natural gas to one barrel is
based on an energy equivalent conversion method primarily applicable at the
burner tip and does not represent a value equivalency at the wellhead. Given
that the value ratio based on the current price of crude oil as compared to
natural gas is significantly different from the energy equivalency of 6:1,
utilizing a conversion ratio on a 6:1 basis may be misleading as an indication
of value.


Net asset value calculations: in relation to the disclosure of net asset value
("NAV"), the NAV table shows what is normally referred to as a "produce out" NAV
calculation under which the current value of the Company's reserves would be
produced at forecast future prices and costs and do not necessarily represent a
"going concern" value of the Company. The value is a snapshot in time and is
based on various assumptions including commodity price forecasts and foreign
exchange rates that vary over time. It should not be assumed that the future net
revenues estimated by Sproule represent the fair market value of the reserves,
nor should it be assumed that Artek's estimated value for its undeveloped land
holdings represent the current fair market value of the lands.


Artek is a crude oil and natural gas exploration, development and production
company headquartered in Calgary, Alberta, Canada. Artek's shares trade on the
TSX under the symbol "RTK".


FOR FURTHER INFORMATION PLEASE CONTACT: 
Artek Exploration Ltd.
Darryl Metcalfe
President and Chief Executive Officer
[phone]


Artek Exploration Ltd.
Darcy Anderson
Vice President Finance and Chief Financial Officer
[phone]