CALGARY, ALBERTA–(Marketwired – Aug. 13, 2014) – 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 six months ended June 30, 2014. A complete copy of the Company’s comparative financial statements for the three and six months ended June 30, 2014, 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 June 30||Six Months Ended June 30|
|(000s, except per share amounts)||($)||($)||(%)||($)||($)||(%)|
|Petroleum and natural gas|
|Funds flow from operations (1)||6,777||6,622||2||16,650||13,541||23|
|Per share – basic||0.10||0.11||(9)||0.24||0.24||—|
|Cash from operating activities||10,787||5,508||96||18,491||12,996||42|
|Per share – basic||0.03||0.03||—||0.05||0.05||—|
|Net debt (2)||54,935||36,947||49||54,935||36,947||49|
|Natural gas (mcf/d)||14,355||11,813||22||15,068||12,242||23|
|Crude oil (bbls/d)||913||1,020||(10)||969||1,076||(10)|
|Average wellhead prices (4)|
|Natural gas ($/mcf)||4.64||3.90||19||5.37||3.74||44|
|Crude oil ($/bbl)||92.27||88.60||4||91.38||86.32||6|
|Operating cost ($/boe)||(12.82)||(10.67)||20||(12.62)||(10.08)||25|
|Transportation cost ($/boe)||(1.72)||(1.97)||(13)||(2.18)||(1.93)||13|
|Operating netback ($/boe)(6)||24.35||25.28||(4)||27.22||25.13||8|
|General and administrative expense ($/boe)||2.90||2.73||6||2.44||2.60||(6)|
|Interest expense ($/boe)||1.69||0.29||483||1.53||0.76||101|
|Funds flow netback ($/boe)||19.76||22.26||(11)||23.25||21.77||7|
|Drilling activity – gross (net)|
|Development (#)||2 (1.2)||1 (0.6)||8 (5.1)||6 (3.0)|
|Exploration (#)||—||1 (1.0)||—||3 (2.2)|
|Total (#)||2 (1.2)||2 (1.6)||8 (5.1)||9 (5.2)|
|Average working interest (%)||60||80||64||58|
|(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/losses from financial derivative instruments.|
|(5)||Oil equivalent price includes minor sulphur sales revenue.|
|(6)||Operating netback equals petroleum and natural gas revenues plus realized gains or 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.|
|(7)||Funds flow netback equals petroleum and natural gas revenues plus realized gains or losses on financial derivatives less royalties, transportation, operating costs, general and administrative expenses and interest calculated on a per boe basis. Funds flow 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.|
Second Quarter Financial and Operating Highlights
- Increased average production to 3,769 boe/d, up 15% from the second quarter of 2013.
- Increased crude oil and liquids volumes 6% to 1,376 bbls/d, which represents 37% of total production.
- Increased funds flow from operations 2% to $6.8 million.
- Increased net earnings 18% to $2.0 million.
- Drilled 2 (1.2 net) wells at Inga, British Columbia.
- Invested $16.0 million in capital expenditures, including $0.6 million on undeveloped land acquisitions in our core operating areas and $0.7 million on facilities.
- Closed a bought deal equity financing pursuant to which Artek issued 8.05 million common shares at a price of $4.10 per share and 1.99 million flow-through common shares at a price of $5.04 per share for aggregate gross proceeds of $43.0 million.
The Company invested $16.0 million in capital expenditures during the second quarter of 2014, including the drilling of 2 (1.2 net) wells at Inga. Second quarter capital investment included $0.6 million on undeveloped land acquisitions in our core operating areas and $0.7 million on facilities.
Artek’s average production for the three-month period ended June 30, 2014 was 3,769 boe/d (37% liquids), up 15% from the previous year. During the period, funds flow increased 2% to $6.8 million and net earnings rose 18% to $2.0 million. The Company’s operating netback and funds flow netback were $24.35/boe and $19.76/boe, respectively, in the second quarter. Artek’s natural gas prices for the quarter rose 19% to $4.64/mcf compared to the same period in 2013.
On June 3, 2014, the Company closed a bought deal equity financing pursuant to which Artek issued 8.05 million common shares at a price of $4.10 per share and 1.99 million flow-through common shares at a price of $5.04 per share for aggregate gross proceeds of $43.0 million. Consequently, the Company’s working capital deficiency of $54.9 million at June 30, 2014 was down 20% from year-end.
Artek has secured 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. In addition, 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.
Artek’s second quarter production was down 10% from the first three months of the year to 3,769 boe/d due primarily to mechanical issues at Inga (as described in prior press releases) causing delays in production on-stream dates until after spring breakup and negatively impacting the quarter by approximately 400 boe/d. Consequently, the Company recorded no new production incrementals between the third week of February and early June. In addition, Artek has been experiencing increased pipeline pressures due to friction related to the high liquids flow and this has resulted in more significant back out of historical low pressure production than anticipated. Artek has budgeted for further pipeline looping to improve total production efficiency at its Inga/Fireweed properties during the second half of the year. In the Mulligan area, the Company is in the early stages of developing the production methodology for its new Charlie Lake oil play and experienced some production curtailments related to limited water disposal capacity. As a result, during the quarter Artek realized more downtime (approximately 200 boe/d) than anticipated due to optimizing its artificial lift systems and commissioning its new water disposal facility. Going forward, the Company expects to see a consistently better run time, and the start-up of its 100% operated water disposal facility during the second quarter at Mulligan should result in an approximate 50% to 60% improvement to operating netbacks for the play.
Due to the delays experienced earlier in the year, the Company has had two rigs running since breakup and drilled two Doig horizontal wells at Inga during the second quarter and anticipates regaining production momentum by the end of the third quarter. Early in the third quarter, Artek completed both wells in the liquids-rich Inga South area of the play using slickwater frac methodology. The first well at 10-17-87-23 W6M (the most southerly Doig horizontal well drilled to date) tested at a restricted rate of approximately 2.9 mmcf/d of natural gas and 641 bbl/d of condensate or 1,086 boe/d at a flowing pressure of approximately 606 PSI over the last 12 hours of an 89-hour clean up production test period. The second well located at 4-33-87-23W6M tested at approximately 3.7 mmcf/d of natural gas and 1,131 bbl/d of free condensate or 1,740 boe/d at a flowing pressure of 1,066 PSI over the last 12 hours of a 56-hour clean up production test period. The Company has drilled two water source wells and has reduced its well completion costs by approximately 25% to between $3.0 million and $3.5 million on its last three Doig horizontal completions. By the fourth quarter of 2014, the Company anticipates it will have enough water disposal capacity to reduce completion costs a further 10%. The Company is observing better test and liquids rates on its Doig wells in these early stages of utilizing slickwater technology in 2014 and anticipates it will result in lower declines and greater recoverable reserves per well.
The Company is currently drilling its first Montney well of the year at a-65-I in the Fireweed area and anticipates completing the well using a 30 to 35-stage slickwater frac program in late August, which will be its highest frac effort utilized to date on the Montney play. In addition, Artek is drilling a fourth horizontal Doig well at 11-16-87-23W6M in the Inga South area.
Given the balance sheet flexibility provided by the $43 million equity financing completed in June, Artek plans to expand its capital program for the remainder of 2014. Budgeted are an additional two horizontal wells at Inga/Fireweed, an additional water disposal well, and approximately $2 million in pipeline debottlenecking and compression at Inga aimed at reducing some of the line pressure issues experienced with its more liquids-rich wells. Given the additional capital required to remediate mechanical issues experienced during the first half of the year and the budgeted capital expansion, Artek anticipates total 2014 capital expenditures to be approximately $86 million to $88 million comprised of 16 (9.6 net) wells, including 12 (6.8 net) wells at Inga/Fireweed, and approximately $10 million for facilities, pipelines, land and seismic. Because of the significance of the production delays experienced during the second quarter and the capital budget increase not occurring until the second half of the year, 2014 average production is now expected to be between 4,300 and 4,500 boe/d with year-end exit production increasing over prior forecast to approximately 5,500 to 5,600 boe/d, of which approximately 39% to 40% is expected to be liquids.
Assuming second half 2014 commodity prices of $4.00/GJ for AECO natural gas, US$95.00/bbl WTI for crude oil and a Canadian/US dollar exchange rate of US$0.91, Artek forecasts to generate annualized cash flow of approximately $37 million to $38 million with exit 2014 forward annualized cash flow estimated at approximately $56 million to $57 million.
Forward Looking Statements: This press release contains forward-looking statements. Management’s assessment of future plans and operations and the timing thereof, the Company’s 2014 capital expenditure plans including the number and locations of wells to be drilled, future results from operations, anticipated production efficiency improvements, commodity mix, initial production rates, expectations to improve completion costs, financial capacity to carry out its planned 2014 capital program, forecasted 2014 average and exit production and forecasted annualized cash flow estimates 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, 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”.
Artek Exploration Ltd.
President and Chief Executive Officer
(403) 296-4799Artek Exploration Ltd.
Vice President Finance and Chief Financial Officer