CALGARY, ALBERTA--(Marketwired - Aug. 7, 2014) - Arsenal Energy Inc. ("Arsenal") (TSX:AEI)(PINKSHEETS:AEYIF) is pleased to release its 2014 Q2 financial and operational results.
Cash flow for the second quarter was $11.6 million or $.72/share, a 14% increase from 2013 Q2. The Board of Directors has declared a 7.7% increase in the quarterly dividend to $.07 per common share. This increase is the second increase in the dividend so far in 2014 and is consistent with Arsenal's dividend policy of paying out in dividends approximately 10% of trailing quarterly cash flow. The dividend is payable (in either cash, or for Shareholders who elect to participate in Arsenal's Share Dividend Plan, in common shares on August 29, 2014 to shareholders of record at the close of business on August 18, 2014. The ex-dividend date is August 14, 2014. Shareholders wishing to participate in the Share Dividend Plan should contact their broker or intermediary or, in the case of registered shareholders, contact our transfer agent, Alliance Trust Company, or visit our website to obtain the necessary enrolment forms.
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SUMMARY OF FINANCIAL RESULTS
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Three Months Ended Six Months Ended
June 30 June 30
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(000'S Cdn. $ except per share
amounts) 2014 2013 2014 2013
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Oil and gas revenue 30,902 22,405 58,508 43,522
Net cash from operating activities 6,619 8,491 14,248 17,144
Funds from operations 11,610 10,011 22,663 17,151
Per share - basic 0.72 0.63 1.41 1.09
Per share - diluted 0.71 0.63 1.39 1.08
Net income (loss) (376) 2,957 652 (1,691)
Per share - basic (0.02) 0.19 0.04 (0.11)
Per share - diluted (0.02) 0.19 0.04 (0.11)
Net debt 84,416 67,078 84,416 67,078
Capital expenditures 17,451 9,116 29,640 20,693
Property acquisitions - - 152 -
Property dispositions - (3,934) - (3,934)
Shares outstanding - end of period 16,074 16,070 16,074 16,070
Net wells drilled
Oil 3.16 1.87 7.76 4.70
Dry and other 1.20 - 1.20 -
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Total net wells drilled 4.36 1.87 8.96 4.70
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Funds from operations for Q2 2014 totaled $11.6 million or $0.72 per share basic versus $10.0 million or $0.63 per share basic for Q2 2013. The increase in cash flow is primarily attributable to increased production volumes from new Mannville wells at Princess. Average production of 4,292 boe/d during the second quarter was up 16% when compared to the second quarter of 2013.
Arsenal's average price received increased by $12.70 per boe compared to the same period in 2013. The higher prices combined with the production increase boosted revenue to $30.9 million, up 38% compared to Q2 2013. The higher prices were partially offset by hedging losses of $2.2 million or $5.76 per boe in the quarter.
Operating costs increased by $2.69 per boe compared to Q2 2013 due to temporary trucking at Princess and one time prior period adjustments. Overall operating costs are expected to drop as battery modifications and water disposal facilities at Princess come on line through the third quarter. Royalties increased by $5.72 per boe compared to Q2 2013 due to higher prices and a larger proportion of production coming from higher rate freehold lands. Arsenal's Q2 2014 production mix was 33% light oil, 46% medium and heavy oil, and 21% natural gas. The resulting Q2 2014 operating margin of $40.69 per boe was 13% higher than the $36.08 per boe operating margin in Q2 2013.
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SUMMARY OF OPERATIONAL RESULTS
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Three Months Ended Six Months Ended
June 30 June 30
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(000'S Cdn. $) 2014 2013 2014 2013
Daily production
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Heavy oil (bbl/d) 36 66 41 64
Medium oil and NGLs (bbl/d) 1,912 1,360 1,774 1,393
Light oil and NGLs (bbl/d) 1,438 1,303 1,368 1,298
Natural gas (mcf/d) 5,435 5,868 6,102 6,010
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Oil equivalent (boe/d @ 6:1) 4,292 3,707 4,201 3,756
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Realized commodity prices ($Cdn.)
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Heavy oil (bbl) 87.94 75.60 78.85 67.09
Medium oil and NGLs (bbl) 89.93 78.54 88.17 74.01
Light oil and NGLs (bbl) 96.56 87.96 96.58 88.13
Natural gas (mcf) 4.71 3.38 5.15 3.11
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Oil equivalent (boe @ 6:1) 79.12 66.42 76.95 64.02
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Netback ($ per boe)
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Revenue 79.12 66.42 76.95 64.02
Royalty (17.54) (12.14) (16.14) (12.75)
Operating cost (20.89) (18.20) (21.09) (20.16)
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Operating netback per boe 40.69 36.08 39.72 31.10
General and administrative (2.94) (3.39) (2.81) (3.29)
Finance expenses (1.80) (1.62) (1.80) (1.85)
Realized loss on risk management
contracts (5.76) (0.51) (4.99) (0.29)
Other (FX and current tax) (0.46) (0.88) (0.32) (0.45)
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Funds from operations per Boe 29.72 29.68 29.81 25.23
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So far in 2014, Arsenal has participated in operations on 10 (3.1 net) Bakken/ThreeForks horizontal wells in North Dakota. Three of those (1.8 net) were fracked and placed on production at the end of the second quarter. Results of those wells were previously released. It is anticipated that the remaining seven wells (1.3 net) will be completed and placed on production by the end of the third quarter. Bakken wells typically produce at an average rate of 630 boe/d for the first month and 260 boe/d for the first year.
At Princess, Alberta, commencing in the second quarter and continuing into the third quarter Arsenal drilled a four (4 net) well program targeting Lower Mannville channels. Three wells were cased as oil wells and one was abandoned. Subsequent to quarter end the three oil wells were completed. The first well swab tested oil at a rate of 330 bbls/d, the second well flow tested oil at a rate of 280 bbls/d, and the third well flow tested at a rate of 585 bbls/d. It is anticipated that all three wells will be tied in by the end of the third quarter. Arsenal expects that the sustained production rates from these wells will be approximately half the test rate. Production from Princess is limited by oil processing capacity and water disposal capacity. Arsenal has initiated a debottlenecking program to accommodate the restricted volumes. An expansion of oil processing capacity at Arsenal's eastern battery has been completed. Capacity has been doubled from approximately 1000 bbls/d of oil to 2,000 bbls/d of oil. An expansion of the water disposal capacity is ongoing and should be completed by the end of the third quarter.
Outlook
Because of Arsenal's exploration success at Princess, the capital budget has been increased from $44 million to $56 million. The increased capital will fund the facility expansion as well as large increases in the land and seismic budgets at Princess, Alberta. Since the end of Q1, 2014 Arsenal has increased its Princess undeveloped land base and currently holds approximately 29,000 net acres. The drilling inventory has increased from 20 locations to 35 locations and includes a mix of relatively low risk development wells, moderate risk step out wells, and higher risk exploration tests. The increased capital budget is expected to be funded from the recently closed $7.5 million flow through equity financing and from higher than budgeted cash flow.
Due to the drilling results at Princess, Arsenal is raising its estimate of average production for the year to 4,600 boe/d. Cash flow guidance for 2014 is increased to $52 million. Debt at yearend is projected at $73 million or 1.4 X 2014 estimated cash flow.
Full financial details are contained in the financial statements and MD&A filed on SEDAR and on the Company's website at:
www.arsenalenergy.com.
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 beca use 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 in0dustry 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 will be filed on SEDAR and can be accessed at
www.sedar.com on filing. 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 cash flow, funds 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, cash flow and funds from operations reflects cash generated from operating activities before changes in non-cash working capital, decommissioning liabilities settled, exploration and evaluation expenses and transaction costs. Management considers cash flow and funds from operations important as it helps evaluate performance and demonstrates the ability to generate sufficient cash to fund future growth opportunities and repay debt. Net debt includes bank debt outstanding plus or minus working capital 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 and operating and transportation expenses divided by production for the period. Cash flow, funds 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 operating activities or other measures of financial performance calculated in accordance with IFRS.
Natural gas volumes have been converted to barrels of oil equivalent ("boe""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.
There is no assurance that future dividends will be declared or the timing or amount of any future dividend. The payments of dividends or distributions in the future are within the discretion of the Corporation's Board of Directors and are dependent on numerous factors including the Corporation's cash flow, capital expenditure budgets, earning, financial conditions, the satisfaction of the applicable solvency test in the Corporation's governing statue (the Business Corporation Act (Alberta)), and such other factors as the Board of Directors may consider appropriate from time to time. The Corporation's ability to continue to pay dividends in the future is also subject to many other factors including falling commodity prices, repatriation restrictions, disruptions or reductions in production or collection of receivables following sales of production. Dividend payments to shareholders will be subject to applicable statutory deductions and tax withholdings prescribed by the applicable law. There is also no assurance that future drawdowns of the secured term loan facility will be available to the Corporation when requested or at all.
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