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In many cases, the end of the year gives you time to step back and take stock of the last 12 months. This is when many of us take a hard look at what worked and what did not, complete performance reviews, and formulate plans for the coming year. For me, it is all of those things plus a time when I u...
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Artek Exploration Ltd. Announces Third Quarter 2012 Financial Results and Updates Operations

CALGARY, ALBERTA -- (Marketwire) -- 11/08/12 -- Artek Exploration Ltd. (TSX:RTK) of Calgary, Alberta ("Artek" or the "Company") is pleased to provide this summary of its financial and operating results for the three and nine months ended September 30, 2012. A complete copy of the Company's comparative financial statements for the three and nine months ended September 30, 2012, along with management's discussion and analysis in respect thereof will be filed on SEDAR and on the Company's website at www.artekexploration.com.

HIGHLIGHTS


----------------------------------------------------------------------------
                              Three Months Ended       Nine Months Ended    
                                 September 30             September 30      
                           -------------------------------------------------
                              2012    2011  Change     2012    2011  Change 
----------------------------------------------------------------------------
(000s, except per share                                                     
 amounts)                       ($)     ($)     (%)      ($)     ($)     (%)
Financial                                                                   
Petroleum and natural gas                                                   
 revenues                    8,501  11,566     (27)  27,610  32,626     (15)
Funds flow from operations                                                  
 (1)                         3,107   5,318     (42)   9,978  14,681     (32)
  Per share - basic           0.07    0.13     (46)    0.23    0.39     (41)
            - diluted         0.07    0.13     (46)    0.23    0.39     (41)
Cash from operating                                                         
activities                   2,959   5,153     (43)   9,391  14,636     (36)
Net earnings (loss)         (1,213)  1,914            7,696    (747)        
  Per share - basic          (0.03)   0.05             0.18   (0.02)        
            - diluted        (0.03)   0.05             0.18   (0.02)        
Capital expenditures        14,857  11,084      34   42,134  30,172      40 
Dispositions                    --      --      --   19,444      --      -- 
Net debt (at period-end)                                                    
 (2)                        61,406  50,868      21   61,406  50,868      21 
Shareholders' equity       102,657 101,285       1  102,657 101,285       1 
----------------------------------------------------------------------------
(000s)                          (#)     (#)     (%)      (#)     (#)     (%)
Share Data                                                                  
At period-end                                                               
  Basic                     43,474  39,583      10   43,474  39,583      10 
  Options                    4,121   3,455      19    4,121   3,455      19 
Weighted average                                                            
  Basic                     43,455  39,583      10   43,442  37,798      15 
  Diluted                   43,826  39,889      10   43,835  37,798      16 
----------------------------------------------------------------------------
                                                (%)                      (%)
Operating                                                                   
Production                                                                  
  Natural gas (mcf/d)        9,722   8,406      16    9,573   8,068      19 
  Crude oil (bbls/d)           743   1,022     (27)     821     914     (10)
  NGLs (bbls/d)                193      75     157      160      74     116 
  Total (boe/d)(3)           2,556   2,498       2    2,577   2,332      11 
Average wellhead prices (4)                                                 
  Natural gas ($/mcf)         2.49    4.52     (45)    2.27    4.57     (50)
  Crude oil ($/bbl)          78.47   83.18      (6)   80.48   86.38      (7)
  NGLs ($/bbl)               50.95   72.02     (29)   60.98   73.43     (17)
  Total ($/boe)(5)           36.50   51.98     (30)   38.30   52.38     (27)
Royalties ($/boe)            (6.03) (11.06)    (45)   (7.10) (10.55)    (33)
Operating cost ($/boe)      (10.11) (11.06)     (9)  (10.51) (11.33)     (7)
Transportation cost ($/boe)  (1.84)  (1.70)      8    (1.64)  (1.75)     (6)
Operating netback                                                           
 ($/boe)(6)                  18.52   28.16     (34)   19.05   28.75     (34)
Drilling activity - gross                                                   
 (net)                                                                      
  Development (#)           5 (2.4) 1 (0.6)          8 (5.0) 3 (1.5)        
  Exploration (#)           -- (--) 1 (0.6)          2 (1.2) 2 (1.6)        
  Abandoned (#)             -- (--) -- (--)          -- (--) -- (--)        
----------------------------------------------------------------------------
  Total (#)                 5 (2.4) 2 (1.2)         10 (6.2) 5 (3.1)        
Average working interest                                                    
 (%)                            48      60               62      62         
Success rate (%)               100     100              100     100         
----------------------------------------------------------------------------

(1) Funds flow from operations is calculated using cash flow 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/losses from financial derivative contracts.

(5) Oil equivalent price includes minor sulphur sales revenue.

(6) Operating netback equals petroleum and natural gas revenues plus realized gains/losses on financial derivatives less royalties, transportation and operating costs calculated on a per 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.

Third Quarter Financial and Operating Highlights


--  Drilled 2 (1.2 net) horizontal wells at Inga, British Columbia resulting
    in production test rates of 2,335 boe/d (1,503 bbls/d of condensate) and
    2,086 boe/d (1,351 bbls/d of condensate), respectively, from the Doig
    formation. 
--  Drilled 3 (1.2 net) vertical wells targeting Glauconite oil at Leduc
    Woodbend in central Alberta all of which are expected to be on
    production by mid-November.  
--  Increased average production to 2,556 boe/d, up 2% from the third
    quarter of 2011 despite shutting in an average of approximately 200
    boe/d of dry natural gas volumes due to low natural gas prices during
    the period and selling approximately 218 boe/d in the first quarter of
    2012. 
--  Crude oil and liquids volumes totaled 936 bbls/d or 37% of total
    corporate production. 
--  Funds flow from operations for the quarter was $3.1 million or $0.07 per
    diluted share. 
--  Operating netbacks declined 34% to $18.52/boe due to natural gas prices
    falling 45% and crude oil prices dropping 6% since the third quarter of
    2011 as well as lower crude oil volumes as a result of a first quarter
    asset sale.  
--  Operating costs decreased 9% to $10.11/boe compared to the third quarter
    of 2011 and fell 7% to $10.51/boe compared to the first nine months of
    2011. 
--  Invested $14.9 million in capital expenditures, including approximately
    $2.0 million on land acquisitions in its core areas and approximately
    $0.9 million on construction of a sales line at Inga to a deeper cut
    facility in order to double the liquids recovery at plant. 
--  Increased operating bank line to $65.0 million from $60.0 million, while
    maintaining the acquisition/development line of credit at $10.0 million.
--  Subsequent to quarter-end, the Company entered into a bought deal
    financing where Artek has agreed to issue 4,562,000 common shares at a
    price of $2.85 per share and 3,189,000 flow-through common shares at a
    price of $3.45 per share for aggregate gross proceeds of approximately
    $24.0 million. The financing is expected to close on or about November
    9, 2012.

FINANCIAL SUMMARY

For the third quarter of 2012, Artek's funds flow declined 42% to $3.1 million compared to the same period last year due to a 45% year-over-year drop in natural gas prices and a 6% decrease in crude oil prices. The Company continued to have approximately 200 boe/d of dry natural gas production shut-in throughout the period due to low natural gas prices. Despite these occurrences and the divestiture of 218 boe/d (approximately 94% oil and liquids) in the first quarter, the Company posted a 2% increase in average production to 2,556 boe/d. Artek's 37% oil and liquids weighting, after a first quarter asset sale, allowed the Company to achieve a quarterly operating netback of $18.52/boe and a cash netback of $13.21/boe despite lower commodity prices. Operating costs improved 9% to $10.11/boe for the quarter compared to the same period last year, while improving 7% over the first nine months of 2011.

The Company's working capital deficiency (excluding fair value of derivative instruments) was $61.4 million at September 30, 2012. Artek's operating bank line was increased to $65.0 million from $60.0 million during the quarter, while the Company's $10.0 million development/acquisition facility was maintained, bringing total credit lines to $75 million.

On October 17, 2012, the Company entered into an agreement with a syndicate of underwriters pursuant to which Artek has agreed to issue, on a bought deal basis, 4,562,000 common shares at a price of $2.85 per share and 3,189,000 flow-through common shares at a price of $3.45 per share for aggregate gross proceeds of approximately $24.0 million. In addition, the underwriters have been granted an over-allotment option, exercisable for a period of 30 days following closing of the offering, to purchase 351,000 common shares at a price of $2.85 per share for additional gross proceeds of approximately $1.0 million. The offering is expected to close on or about November 9, 2012. The proceeds of the financing will be used initially to reduce bank indebtedness, thereby freeing up additional borrowing capacity that may be redrawn to fund the Company's ongoing capital expenditure program.

Operations Review - Liquids Focus

Artek's production in the third quarter averaged 2,556 boe/d, of which approximately 37% was crude oil and NGLs. Production during the period was impacted by temporary delays associated with weather and mechanical issues experienced during the drilling and completion of the second and third horizontal wells drilled in the Inga area during the second quarter of 2012. As disclosed in prior communications, during the drilling of its second horizontal well of the year at Inga, Artek encountered an over pressured and flowing uphole zone that required the Company to set intermediate casing and drill out "slim hole" limiting the horizontal lateral to 618 metres, or approximately half of the lateral distance typically drilled and correspondingly, approximately half of the fracture effort. Consequently, production from this well was proportionately lower. The third well was drilled as a horizontal re-entry of an existing vertical well, to save on drilling and onstream costs, and therefore, was conducted as a "slim-hole" operation. Mechanical difficulties were experienced early in the completion of this well, and as a result, no incremental volumes from the operation were realized during the third quarter. Remedial work on this third horizontal well is currently underway and completion of the operation is scheduled during the fourth quarter of this year.

Eight out of Artek's ten operations concluded to date, at Inga, have been executed with conventional sized hole from surface with a high degree of success and results have been strong with details provided previously and in line with management expectations. Approximately 200 boe/d of dry natural gas volumes remained shut-in during the quarter due to low natural gas prices.

During the three months ended September 30, 2012, Artek invested approximately $14.9 million in capital expenditures. The Company invested approximately $2.0 million on land acquisitions in its core operating areas and approximately $0.9 million for the construction of a sales line at Inga to a deeper cut facility, increasing Artek's liquids recovery at plant by approximately 100% from 15 bbls/mmcf to approximately 30 to 35 bbls/mmcf above and beyond the free liquids recovered at the Company's facility. The remainder of the capital was allocated to drill related operational expenditures including the acceleration of a fourth quarter operation into late third quarter. The Company drilled 2 (1.2 net) horizontal wells targeting condensate-rich natural gas at Inga resulting in production test rates of 2,335 boe/d (1,503 bbls/d of condensate) and 2,086 boe/d (1,351 bbls/d of condensate), respectively, from the Doig formation. The first horizontal well (fourth of 2012) was completed and placed on production in September. During the final six hours of a 103-hour in-line production test period, the well produced at a restricted average rate of approximately 6.7 mmcf/d of natural gas (26% load C3) and 1,503 bbls/d of condensate or a total of 2,623 boe/d, which is the equivalent of 2,335 boe/d (64% condensate) net of load at a flowing pressure of 1,118 PSI. The second horizontal well (fifth of 2012) was drilled at A16-10-88-23 W6M, which is located at the most northerly end of its Doig natural gas and condensate trend. During the final six hours of a 93-hour in-line production test period, the well produced at a restricted average rate of approximately 6.4 mmcf/d of natural gas (31% load C3) and 1,351 bbls/d of condensate or a total of 2,424 boe/d, which is the equivalent of 2,086 boe/d (65% condensate) net of load at a flowing pressure of 1,486 PSI. The well was drilled to a lateral distance of approximately 1,560 metres and was completed with a 16-stage propane fracture stimulation program and placed on production in late October. At Leduc Woodbend, the Company drilled 3 (1.2 net) vertical wells targeting Glauconite oil. These wells have been completed and are expected to be on production by mid-November.

Outlook

Four of the seven 2012 planned horizontal wells at Inga are currently on production. In addition, the Company has completed the drilling of its final two horizontal wells in the program and the packer assemblies for typical twelve and thirteen stage fracs, respectively, have been set for the completions. Both of these wells are scheduled for completion by the end of November and anticipated to be on-stream between mid-November and early December. The Company continues to increase its land holdings and drilling inventory in the Inga/Fireweed area as Artek recently closed the acquisition of an additional 5 (2.5 net) sections of Doig mineral rights at the south end of its producing Doig condensate and gas trend.

At Leduc Woodbend, Artek recently completed the drilling of its fourth vertical well (0.4 net) in the Company's Glauconite oil development program, which has been completed and is expected to be on production in November. Artek will assume operatorship of the Leduc Woodbend unit and property on December 1, 2012.

All of these fourth quarter wells are targeted to be on-stream by year-end resulting in 2012 exit production forecast to be approximately 4,000 boe/d (38% to 40% oil and liquids).

ADVISORIES

Forward Looking Statements: This document contains forward-looking statements. Management's assessment of future plans and operations, future results from operations, production estimates including forecast 2012 average and exit rates, commodity mix, initial production rates, drilling plans, the volumes and estimated value of reserves, timing of drilling and tie-in of wells, number of potential drilling locations, productive capacity of new wells, estimates of shut-in production and the timing thereof, future oil and natural gas prices, capital expenditures and the nature and timing of these expenditures, closing of its bought deal financing and timing thereof, cash flow estimates and financial capacity to carry out its planned 2012 capital program 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.

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.

Test results and initial production rates: the pressure transient analysis or well test interpretation has not been carried out and thus certain of the test results provided herein should be considered to be preliminary until such analysis or interpretation has been completed. Test results and initial production rates disclosed herein may not necessarily be indicative of long-term performance or of ultimate recovery.

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".

Contacts:
Artek Exploration Ltd.
Darryl Metcalfe
President and Chief Executive Officer
(403) 296-4799

Artek Exploration Ltd.
Darcy Anderson
Vice President Finance and Chief Financial Officer
(403) 296-4775

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