CALGARY, ALBERTA–(Marketwired – Nov. 6, 2013) – 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, 2013. A complete copy of the Company’s comparative financial statements for the three and nine months ended September 30, 2013, 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.
|Three Months Ended September 30||Nine Months Ended September 30|
|(000s, except per share amounts)||($)||($)||(%)||($)||($)||(%)|
|Petroleum and natural gas revenues||14,568||8,501||71||42,765||27,610||55|
|Funds flow from operations (1)||5,876||3,107||89||19,417||9,978||95|
|Per share – basic||0.09||0.07||29||0.33||0.23||43|
|Cash from operating activities||3,934||2,959||33||16,930||9,391||80|
|Net earnings (loss)||283||(1,213)||123||3,411||7,696||(56)|
|Per share – basic||0.00||(0.03)||100||0.06||0.18||(67)|
|Net debt (at period-end) (2)||68,918||61,406||12||68,918||61,406||12|
|Natural gas (mcf/d)||15,248||9,722||57||13,255||9,573||38|
|Crude oil (bbls/d)||982||743||32||1,045||821||27|
|Average wellhead prices (4)|
|Natural gas ($/mcf)||3.33||2.49||33||3.58||2.27||58|
|Crude oil ($/bbl)||87.75||78.47||12||86.71||80.48||8|
|Operating cost ($/boe)||(10.68)||(10.11)||6||(10.30)||(10.51)||(2)|
|Transportation cost ($/boe)||(1.89)||(1.84)||3||(1.92)||(1.64)||17|
|Operating netback ($/boe)(6)||19.56||18.52||6||23.10||19.05||21|
|Drilling activity – gross (net)|
|Development (#)||3 (2.2)||5 (2.4)||9 (5.2)||8 (5.0)|
|Exploration (#)||1 (0.6)||— (–)||4 (2.8)||2 (1.2)|
|Total (#)||4 (2.8)||5 (2.4)||13 (8.0)||10 (6.2)|
|Average working interest (%)||70||48||62||62|
|Success rate (%)||100||100||100||100|
(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 contracts.
(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 revenue 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
- Increased average production to 3,884 boe/d, up 52% from the third quarter of 2012 and 19% from the second quarter of 2013.
- Improved crude oil and liquids volumes 43% to 1,342 bbls/d, of which 73% was oil and condensate, representing 35% of total production.
- Increased funds flow from operations 89% to $5.9 million and 29% on a diluted per share basis to $0.09 per share compared to the third quarter of 2012.
- Closed the Fireweed asset acquisition in northeastern British Columbia, which included approximately 600 boe/d (21% liquids) of production for a total cash consideration of $14.8 million net of adjustments. This transaction builds on our strategy of continuing to consolidate a significant resource base in our core Inga/Fireweed area of operations, and as a result, has increased our aggregated area land holdings to 107 (61 net) sections with Doig rights and 120 (71 net) sections with Montney rights along with important infrastructure additions.
- Drilled 4 (2.8 net) wells (100% success rate), including 3 (1.8 net) wells at Inga, two of which are northern and southern pool extensions and 1 (1.0 net) exploration discovery well at Mulligan in the Peace River Arch area of Alberta.
- Invested $38.3 million in capital expenditures, including $14.8 million for the Fireweed asset acquisition and $2.6 million on undeveloped land acquisitions in our core operating areas.
- Increased operating bank line to $90.0 million from $75.0 million in October 2013.
Artek’s average production for the three-month period ended September 30, 2013 was 3,884 boe/d (35% liquids), up 52% from the previous year and 19% from the second quarter of 2013. Liquids production was down slightly in the short-term as a result of adding 600 boe/d (21% liquids) through the Fireweed asset acquisition and bringing on-stream over 400 boe/d of net production (10-14% liquids) at Mulligan. With a liquids-weighted program planned through year-end, the Company anticipates exiting 2013 with liquids production in the 38% to 40% range. An anomalously wet summer and third party plant interruptions at both Inga and Mulligan resulted in restriction or shut-ins of over 300 boe/d during the quarter. During the period, funds flow increased 89% to $5.9 million and 29% on a diluted per share basis to $0.09 per share from last year. The Company’s operating netback was $19.56/boe in the third quarter, up 6% from the previous year but down from $25.28/boe in the second quarter due to the short term reduction in liquids percentage and a 15% decrease in natural gas prices quarter to quarter.
Subsequent to September 30, 2013, the Company’s bank operating line was increased to $90.0 million from $75.0 million with the next review scheduled for January 2014.
Artek has entered into several commodity contracts to protect its cash flow and support its capital budget for the remainder of the year. The Company has put a floor price of $3.00/GJ on 6,000 mmbtu/d of natural gas production for the period April to October 2013. As part of the same transaction for the same period, Artek sold a call on 600 bbls/d of crude oil production at an average price of CDN$101.37/bbl WTI. The Company has also entered into natural gas production swaps on 2,000 mmbtu/d from April to December 2013 at a fixed price of $3.27/GJ and 1,000 mmbtu/d at a fixed price of $3.41/GJ from April to October 2013. Lastly, 200 bbls/d of crude oil production has been fixed at CDN$96.00/bbl WTI for the period June to December 2013, 100 bbls/d has been fixed at CDN$103.00/bbl from August to December 2013 and the AECO Basis for 3,000 mmbtu/d has been fixed at CDN$0.445/mmbtu from November to December 2013.
Operations Review – Second Half Liquids Focus
During the quarter, Artek drilled 4 (2.8 net) wells with a 100% success rate, including three horizontal Doig wells at Inga and a horizontal well at Mulligan targeting Charlie Lake oil. Total capital investment during the quarter was $38.3 million, including $14.8 million for the Fireweed asset acquisition and $23.5 million of exploration and development capital that included $2.6 million on undeveloped land acquisitions in our core operating areas, and $3.2 million of pipeline and facilities investment to accommodate exploration successes at Inga South and the Mulligan areas.
Late in the third quarter, Artek drilled an Inga vertical pilot well from a pad at 13-16-87-23 W6 which the Company believes is a significant pool extension at Inga South. The well is more than 3 miles south of the closest producer on lands largely acquired in 2013 and not evaluated in our December 31, 2012 reserve report. The vertical well encountered 65 metres of clean Doig sand (versus the average of approximately 40 metres in the producing Inga pool to the north) and was drilled out horizontally in October. The well has recently been completed using a 17 stage propane frac and after 128 hours of total production test period, the well was flowing at an average restricted rate of 4.2 mmcf/d (24% load propane) and 1,230 bbl/d of free condensate over the last 6 hours of the test at a flowing pressure of 937 PSI or 1,760 boe/d (net of load) of which 70% was condensate delivering a free liquids ratio of 387 bbls/mmcf. The Inga South stepout well at 13-16 (Artek’s 16th Doig horizontal well), has produced one of the highest test rates and the uppermost free condensate yield of wells drilled by the Company on the play to date. The Company believes the well validates an additional seven sections of land as prospective for high liquids yield Doig. Earlier in the quarter, Artek drilled two Inga horizontal wells that averaged approximately 850 boe/d at 43% liquids over the first 30 days of production. The average 30 day production rate for the Inga Doig horizontal wells drilled to date continues to track in excess of 1,000 boe/d at approximately 42% liquids. The remainder of the Doig drilling for the year is focused at the south end of the Doig pool trend where higher liquids yields have been historically realized. A second Doig horizontal is currently being drilled one mile further south of the new Inga South discovery at 10-17-87-23 W6M to further delineate this extension and should be finished drilling in the third week of November with the completion scheduled for the end of November. Artek is scheduled to spud a final Doig well prior to year end also in the Inga South area.
Artek is also drilling an exploration horizontal Montney well at Inga South from the 10-17-87-23W6M pad. The vertical pilot well drilled at 13-16 was drilled and logged into the Montney with encouraging results on logs. The well should reach total depth in late November and is scheduled for completion in December. The Company’s previous two Montney wells have realized very high liquids ratios in excess of 100 bbls/mmcf. Industry is having success on similarly high liquids yield Montney by utilizing slickwater and greater numbers of fracs and as a result Artek is planning to complete the well using up to a 30 stage slickwater frac program which represents a significant increase in effort. The Company and its partner in the Inga area continue to increase their landholdings bringing total Montney mineral rights in the Inga/Fireweed area to over 87,800 (51,500 net) acres or approximately 129 (75 net) sections.
The Company also drilled a 100% horizontal well in the Mulligan area targeting crude oil in the Charlie Lake. Artek’s Mulligan horizontal well at 13-10-82-8 W6M was drilled to a lateral length of approximately 1,500 metres and completed using an 18-stage energized water-based fracing system. After a 79-hour clean up test period, the well was flowing at an average rate of 1.1 mmcf/d and 310 bbls/d of 34° API medium gravity crude or a total test rate of approximately 500 boe/d, of which 62% was oil over the last six hours of the production test. We are very encouraged by the results and expect to have the well on production by mid-November. The Company has accumulated approximately 32 (30 net) sections of land that Artek believes are prospective for multi-zone oil and liquids-rich natural gas on this Triassic stratigraphic play that is sandwiched between recent industry activity at Spirit River and the Cecil Triassic oil developments. Industry is developing the trend at four to six horizontal wells per section that could with continued success, add significantly to the Company’s inventory of oil and liquids-rich natural gas locations.
Subject to timing of current wells and its final operations of the year, Artek is forecasting fourth quarter production volumes of approximately 4,300 to 4,500 boe/d. With the two horizontal wells currently drilling at Inga and a final Doig horizontal expected to spud in December, the Company anticipates spending approximately $19 million during the fourth quarter, thereby bringing total capital investment for the year to approximately $95 million (including the asset purchase at Fireweed that closed in the third quarter). The Company is maintaining its guidance with exit production expected to be between 4,800 and 5,000 boe/d (38% to 39% liquids) that, along with the early exploration success experienced during the final quarter of the year, should deliver excellent momentum going into 2014. We look forward to updating you on our remaining operational results.
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 2013 fourth quarter average and exit rates, commodity mix, initial production rates, drilling plans including the number and locations of wells to be drilled, 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, the possible pool extension at Inga South, prospectivity of lands in the Mulligan area, 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, cash flow estimates and financial capacity to carry out its planned 2013 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”.
President and Chief Executive Officer
Artek Exploration Ltd.
Vice President Finance and Chief Financial Officer