CALGARY, ALBERTA–(Marketwired – March 20, 2014) – 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 December 31,||Years Ended December 31,|
|(000s, except per share amounts)||($||)||($||)||($||)||($||)|
|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|
|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||)|
|Net debt (at period end) (2)||(68,451||)||(48,913||)||(68,451||)||(48,913||)|
|Natural gas (mcf/d)||15,972||11,153||13,940||9,970|
|Crude oil (bbls/d)||884||1,059||1,004||881|
|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|
|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||)|
|Total||3 (1.8||)||3 (1.6||)||16 (9.8||)||13 (7.8||)|
|(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.
* 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.
|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|
|Net asset value||389,835|
|Diluted Common shares outstanding (thousands)||71,810|
|Net asset value per share||5.43|
|(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.|
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”.
Artek Exploration Ltd.
President and Chief Executive Officer
(403) 296-4799Artek Exploration Ltd.
Vice President Finance and Chief Financial Officer