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Arsenal Energy Inc. Announces 2012 Fourth Quarter and Year End Results

CALGARY, ALBERTA--(Marketwire - Mar 19, 2013) - Arsenal Energy Inc. (AEI.TO) (AEYIF)

Arsenal is pleased to release its Q4 and full year 2012 financial and operating results. Q4 2012 is highlighted by an 18% increase in cash flow from operations to $10.0 million from $8.4 million generated in Q4 2011. The cash flow increase is primarily due to a 42% increase in light oil production.

  Three Months Ended December 31       Year Ended December 31  
(000''S Cdn. $ except per share amounts) 2012   2011   % Change   2012   2011   % Change  
Oil and gas revenue 22,351   19,089   17   82,168   58,466   41  
Funds from operations 10,000   8,441   18   31,119   29,274   6  
  Per share - basic and diluted 0.06   0.05   20   0.20   0.18   8  
Net loss (896 ) (4,051 ) (78 ) (112 ) (2,545 ) (96 )
  Per share - basic and diluted (0.01 ) (0.03 ) (78 ) 0.00   (0.02 ) -  
Total debt 68,492   55,752   23   68,492   55,752   23  
Capital expenditures 10,749   13,578   (21 ) 42,681   40,471   5  
Property acquisition -   38,575   -   -   38,575   -  
Proceeds on property dispositions -   -   -   (1,928 ) (622 ) 210  
Shares outstanding - end of period 155,948   157,282   (1 ) 155,948   157,282   (1 )
Wells drilled (net)                        
  Oil 1.16   1.40   (17 ) 6.14   6.02   2  
  Gas -   -   -   -   -   -  
  Dry -   -   -   -   3.00   -  
Total net wells drilled 1.16   1.40   (17 ) 6.14   9.02   (32 )
Daily production                        
Heavy oil (bbl/d) 72   124   (42 ) 112   170   (34 )
Light oil and NGLs (bbl/d) 2,949   2,082   42   2,661   1,654   61  
Natural gas (mcf/d) 5,483   4,158   32   5,697   2,439   134  
Oil equivalent (boe @ 6:1) 3,934   2,899   36   3,723   2,230   67  
Realized commodity prices ($Cdn.)                        
Heavy oil (bbl) 71.63   81.85   (12 ) 70.70   70.84   -  
Light oil and NGLs (bbl) 75.31   88.93   (15 ) 76.50   84.47   (9 )
Natural gas (mcf) 2.88   2.93   (2 ) 2.28   3.47   (34 )
Oil equivalent (boe @ 6:1) 61.76   71.57   (14 ) 60.31   71.82   (16 )
Operating netback ($ per boe)                        
Revenue 61.76   71.57   (14 ) 60.31   71.82   (16 )
Royalty (12.26 ) (15.58 ) (21 ) (12.52 ) (14.47 ) (13 )
Operating cost (19.05 ) (19.19 ) (1 ) (20.28 ) (19.44 ) 4  
Operating netback per boe 30.44   36.80   (17 ) 27.50   37.91   (27 )
General and administrative (2.77 ) (2.80 ) (1 ) (3.03 ) (4.88 ) (38 )
Finance expenses (1.63 ) (1.43 ) 14   (1.67 ) (1.15 ) 46  
Realized gains (losses) on risk management contracts 1.75   (1.30 ) 235   0.07   4.12   (98 )
Other (0.16 ) 0.38   (143 ) (0.02 ) (0.05 ) (49 )
Funds flow per Boe 27.63   31.65   (13 ) 22.84   35.96   (36 )


Cash flow from operations in the fourth quarter of 2012 totaled $10.0 million ($0.06 per share basic and diluted) up 18% from the fourth quarter of 2011. This increase of 18% from the comparable period in 2011 results from a 36% increase in quarter over comparative quarter production. Lower average commodity prices over the quarter resulted in a decline of 14% in the average price received per Boe and was the major contributor to a 17% decline in the operating netback. General and administrative expenses and interest and other financing charges increased in 2012 over 2011 due to an increase in the number of employees and to a higher average debt level.

Annual 2012 cash flow of $31.1 million ($0.20 per share basic and diluted) was 6% higher than 2011. Cash flow for 2011 included a $3.4 million realized gain on commodity contracts versus a gain of $93,178 in 2012. Interest and other financing charges increased 144% or by $1.4 million in 2012 due primarily to a higher average debt level maintained in 2012.

Arsenal''s Q4 production mix was 77% liquids and 23% natural gas. The operating netback for Q4 2012 of $30.44 was 17% lower than $36.80 received in Q4 2011 due to a $9.81 per boe decline in the average price received. As a result of lower average prices, royalties were lower while operating costs on a boe basis remained constant. For 2012, the operating netback was down $10.41 per boe to $27.50 per boe due to an $11.52 per boe decrease in the average price received. Royalties were therefore lower while operating costs on a boe basis remained constant.

Capital expenditures for Q4 2012 totaled $10.7 million and for 2012 totaled $42.7 million. Of this, $3.3 million was incurred to purchase land at Princess and Galahad in Canada and at Rennie Lake/Black Slough in North Dakota. Total debt at year end was $68.5 million.


Q4 2012 production averaged 3,934 boe/d versus 2,899 for Q4 2011. The 36% improvement in production over Q4 2011 was largely due to increased production of light oil and natural gas liquids from the Bakken in North Dakota, from recent drilling at Princess in Alberta, and from a mid Q4 2011 property acquisition. Production in 2012 increased 67% over 2011 to 3,723 boe/d due to a mid Q4 2011 acquisition of 1,500 boe/day and due to increased production from Bakken wells drilled in North Dakota.

In 2012, at Stanley, North Dakota, Arsenal participated in 8 gross, 2.88 net wells. The Company operated 2 of these wells. In 2012, at Princess, Alberta, the Company drilled two successful Glauconite formation oil wells. Both of these wells were on production in Q4 2012. The Company''s 8-5 well at Princess is currently averaging 255 boe/day after 6 months of production. The company drilled a successful offset well in Q1 2013. 3D seismic has identified, and Arsenal intends to drill, 5 net additional locations at Princess in 2013. The Princess Glauconite represents a significant new discovery that will be the focus of the company''s Canadian development program in 2013.


Due to the widening of oil prices differentials in Canada in Q1 2013, the Company decided to delay Canadian capital projects and accelerate drilling in the North Dakota Bakken where differentials on Company operated Bakken wells has narrowed to approximately $4.00 per bbl. In North Dakota, Arsenal placed 7 gross, 1.11 net Bakken wells on production in Q1 2013 and spudded the first of 2 gross, 1.25 net operated wells that should come on production towards the end of Q2 2013. In addition, it is expected that one gross, 0.20 net partner operated well will be drilled in Q1 2013 with 6 gross, .48 net additional Bakken wells planned for the latter half of 2013.

Total capital expenditures for the year are now estimated at approximately $42.0 million. Arsenal expects 2013 funds from operations to total approximately $40.0 million. Debt at year end is now expected to total approximately $72.0 million. Average 2013 production is estimated at approximately 4,000 Boe per day.

Arsenal''s Annual Information Form which contains Arsenal''s reserves data and other oil and gas information for the year ended December 31, 2012 as mandated by National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities of the Canadian Securities Administrators will be filed shortly and can be obtained on the System for Electronic Document Analysis and Retrieval website at www.sedar.com or by contacting Arsenal.

As previously disclosed, Arsenal together with its advisors, continue to analyze various alternatives by which excess cash flow from its US properties may be efficiently returned to its shareholders, which could include a corporate reorganization or other alternative.

To receive company news releases via e-mail, please advise info@arsenalenergy.com and specify "Arsenal Press Releases" in the subject line.


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.