CALGARY, ALBERTA -- (Marketwired) -- 05/06/13 -- Arsenal Energy Inc. ("Arsenal") (TSX: AEI) (PINKSHEETS: AEYIF) is pleased to release its 2013 Q1 results. Funds from operations for Q1 was up 5% compared to Q1 2012. Expectations were for a larger increase but price differentials for the Company's Alberta medium gravity oil production were wider than expected during the quarter. For the second quarter those differentials have returned to historical levels. Assuming that the differentials remain at current levels, cash flow for the last three quarters of the year should return to the previously anticipated levels totaling approximately $32 million.
Full financial details are contained in the financial statements and MD&A filed on SEDAR and on the Company's web site.
Financial
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Three Months Ended March 31
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(000'S Cdn. $ except per share amounts) 2013 2012 % Change
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FINANCIAL
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Oil and gas revenue 21,117 21,199 -
Funds from operations 7,139 6,799 5
Per share - basic and diluted 0.05 0.04 25
Net loss (4,648) (4,773) (3)
Per share - basic and diluted (0.03) (0.03) -
Total debt 70,641 56,706 25
Capital expenditures 11,578 7,372 57
Property acquisition - (33) (100)
Proceeds on property dispositions - - -
Shares outstanding - end of period 156,944 156,294 -
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Funds from operations for Q1 2013 totaled $7.1 million or $0.05 per share versus $6.8 million or $0.04 per share for Q1 2012. The increase in funds from operations is attributable to increased production volumes from new Bakken wells in North Dakota and new Glauconite wells at Princess, Alberta. Funds from operations on a Boe basis were $20.84 per Boe versus $20.16 per Boe in Q1 2012. The operating margin in Q1 2013 was $26.20 per Boe versus $26.89 per Boe in Q1 2012. The average price received decreased by $1.19 per Boe mostly due to higher price differentials for Arsenal's Canadian medium and heavy grade crude production. Those discounts are due to refinery turnarounds in the US Midwest combined with pipeline bottlenecks. Royalties decreased by $1.32 per Boe and operating costs increased by $0.82 per Boe.
Operations
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Three Months Ended March 31
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(000'S Cdn. $ except per share amounts) 2013 2012 % Change
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OPERATIONAL
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Wells drilled (net)
Oil 2.83 1.68 68
Gas - - -
Dry - - -
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Total net wells drilled 2.83 1.68 68
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Daily production
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Heavy oil (bbl/d) 63 160 (61)
Medium oil (bbl/d) 1,425 1,527 (7)
Light oil and NGLs (bbl/d) 1,292 994 30
Natural gas (mcf/d) 6,153 6,155 -
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Oil equivalent (boe @ 6:1) 3,806 3,707 3
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Realized commodity prices ($Cdn.)
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Heavy oil (bbl) 58.07 77.47 (25)
Medium oil (bbl/d) 69.63 82.15 (15)
Light oil and NGLs (bbl) 88.31 82.27 7
Natural gas (mcf) 2.86 2.16 32
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Oil equivalent (boe @ 6:1) 61.65 62.84 (2)
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Operating netback ($ per boe)
Revenue 61.65 62.84 (2)
Royalty (13.35) (14.67) (9)
Operating cost (22.10) (21.28) 4
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Operating netback per boe 26.20 26.89 (3)
General and administrative (3.19) (2.80) 14
Finance expenses (2.08) (1.56) 33
Realized gains (losses) on risk management
contracts (0.06) (2.32) 97
Other (0.02) (0.05) (54)
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Funds flow per Boe 20.84 20.16 3
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Average production of 3,806 boe/d during the first quarter was up 3% compared to the first quarter of 2012. The increase was from new Bakken wells in North Dakota and new Glauconite wells at Princess, Alberta. For safety reasons, adjacent producers are shut in during frack operations. These shut-ins in both North Dakota and at Princess adversely affected Q1 production volumes by approximately 112 boe/d. Arsenal's Q1 production mix was 34% light oil, 39% medium and heavy gravity oil, and 27% natural gas.
In the first quarter, Arsenal completed and placed on production 6 (1.08 net) Bakken wells in North Dakota. Operations were commenced in the quarter on three (1.45 net) additional wells. All three have finished drilling and it is anticipated that completions will begin in May with all three wells on production by the end of June. Over the last two years the average cost of a North Dakota well has declined to $8.3 million from $10 million due to technical advancements and a more competitive service company pricing environment.
Two wells (2 net) were completed at Princess, Alberta during the quarter. The first well was placed on production and is currently pumping at a rate of 80 bbls/d. The second well is to be placed on production in early May. Arsenal plans to drill four additional wells at Princess in the second quarter.
In the second quarter, Arsenal plans to drill an exploratory horizontal well into the Leduc at Chauvin, Alberta. If successful, Arsenal has identified up to 8 additional drilling locations. Well costs are estimated at $1.1 million each.
Arsenal has entered into a joint venture agreement with a mid-tier producer on Arsenal's Alberta deep basin acreage. The partner is to pay Arsenal approximately $4 million to acquire a 50% working interest in Arsenal's acreage. The partners have agreed to drill a joint well into the Falher formation commencing in Q3 2013. All in well costs are estimated at $8 million.
Outlook
Capital expenditures for 2013 are currently estimated at $43 million. Assuming that the price differentials do not widen from current levels, Arsenal's cash flow should return to previously anticipated levels totaling approximately $32 million for the remainder of the year. The Company expects to exit 2013 at approximately 4,400 boe/d.
As previously disclosed, Arsenal's US properties are now producing cash flow in excess of the capital required for ongoing development. Arsenal's Board of Directors has decided, therefore, to start returning a portion of that excess cash flow to shareholders through a dividend. The Board believes that Arsenal's strong cash flow can fund future organic growth in production and reserves, maintain the dividend, and maintain a targeted debt/cash flow ratio of 1.5:1.
Subsequent to Q1 quarter end Arsenal closed its deep basin JV agreement for $4 million and entered into two agreements for small equity issues totaling $3 million. Arsenal is also negotiating the sale of a small non-core gas property with expected proceeds of approximately $0.5 million. With these initiatives, at the end of Q2, when the new Bakken wells are expected to come on production, Arsenal's debt to cash flow is anticipated to be just over 1.5:1.
To facilitate the conversion to a dividend paying corporation, Arsenal will seek shareholder approval at its 2013 Annual and Special Meeting to consolidate the Company's common shares on a ten-for-one basis. Arsenal's Board of Directors is of the view that the consolidation will contribute to immediate and long-term shareholder value by:
-- realigning the share capital structure to be more consistent with a cash
generating, dividend paying public company:
-- increasing the breadth and sophistication of the Company's eligible
investor base;
-- increasing trading volume in the stock through a broader investor base;
-- increasing the valuation level and investment profile of the common
shares, as the Company should no longer be considered a "penny stock"
-- aligning the nominal market price of the common shares with those of the
Company's peers.
If approved, the consolidation would reduce the Company's issued and outstanding common shares to approximately 16 million common shares. The number and exercise price of outstanding stock options would be proportionately adjusted based upon the same consolidation ratio. The consolidation is subject to the approval of the Toronto Stock Exchange and two-thirds of Arsenal's shareholders.
The dividend would be set quarterly by the Board starting at the end of the second quarter. It is anticipated that the dividend will be initially set at approximately 10% of trailing cash flow.
Full details of the consolidation will be included in the management information circular expected to be mailed on June 3, 2013 to all Arsenal shareholders of record as of May 28, 2013 in connection with the Annual and Special Meeting of Shareholders to be held on June 27, 2013. The circular will also be posted and available on SEDAR at www.sedar.com on or about June 03, 2013.
Advisory
Certain information regarding Arsenal Energy Inc. (the "Company") contained in this press release, including statements regarding management's assessment of future plans and operations, the timing of drilling, tie -in and commencement of production of new wells, productive capacity and economics of new wells and alternatives for increasing liquidity, may constitute forward-looking statements under applicable securities laws. The forward-looking statements are based on certain key expectations and assumptions made by the Company, including expectations and assumptions concerning the success of optimization and efficiency improvement projects, the availability of capital, the success of future drilling and development activities, the performance of existing wells, the performance of new wells, prevailing commodity prices, the availability of labor and services, the geological nature of the formations targeted by the Company and the success of completion and recompletion activities. Although the Company believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because the Company can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), commodity price and exchange rate fluctuations, changes in the regulatory regime applicable to the Company and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures. Certain of these risks are set out in more detail in the Company's Annual Information Form which has been filed on SEDAR and can be accessed at www.sedar.com. The forward-looking statements contained in this presentation are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.
This press release contains financial terms that are not considered measures under International Financial Reporting Standards ("IFRS"), which are considered to be generally accepted accounting principles ("GAAP"), such as funds flow from operations, net debt and operating netback. These measures are commonly utilized in the oil and gas industry and are considered informative for management and stakeholders. Specifically, funds flow from operations reflects cash generated from operating activities before changes in non -cash working capital. Management considers funds flow from operations important as it helps evaluate performance and demonstrate the ability to generate sufficient cash to fund future growth opportunities and repay debt. Net debt includes bank debt outstanding plus accounts payable less accounts receivable and prepaid expense and is used to evaluate The Company's financial leverage. Profitability relative to commodity prices per unit of production is demonstrated by an operating netback. Operating netback reflects revenues less royalties, transportation costs, and production expenses divided by production for the period. Funds flow from operations, net debt and operating netbacks may not be comparable to those reported by other companies nor should they be viewed as an alternative to cash flow from operations or other measures of financial performance calculated in accordance with IFRS.
Natural gas volumes have been converted to barrels of oil equivalent ("boe"). Six thousand cubic feet ("mcf") of natural gas is equal to one barrel based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Boes may be misleading, especially if used in isolation.
Contacts:
Arsenal Energy Inc.
Tony van Winkoop
President and Chief Executive Officer
(403) 262-4854 or Toll free: 1(866) 405-4854
(403) 265-6877 (FAX)
Arsenal Energy Inc.
J. Paul Lawrence
Vice President Finance and Chief Financial Officer
(403) 262-4854 or Toll free: 1(866) 405-4854
(403) 265-6877 (FAX)
Arsenal Energy Inc.
Suite 1900, 639 - 5th Avenue SW
Calgary, Alberta T2P 0M9
info@arsenalenergy.com
www.arsenalenergy.com
