AvenEx Energy Corp.

March 29, 2011 08:00 ET

AvenEx Energy Corp. Announces Fourth Quarter and 2010 Year End Results

CALGARY, ALBERTA--(Marketwire - March 29, 2011) - AvenEx Energy Corp. ("AvenEx" or the "Company") (TSX:AVF) is pleased to announce the financial and operational results for the quarter and year ended December 31, 2010 and to announce they have filed the complete Management Discussion and Analysis and Audited Consolidated Financial Statements. Certain selected financial and operational information is set out below and should be read in conjunction with AvenEx's audited financial statements and related Management Discussion and Analysis. These filings will be available on the Corporation's SEDAR profile at www.sedar.com.

  For the quarter ended December 31   For the year ended December 31  
(in thousands of dollars except for per         %           %  
share amounts) 2010   2009   Change   2010   2009   Change  
Total Revenue $177,606   $204,884   (13 ) $625,537   $870,086   (28 )
Funds (Used In) From Continuing Operations (FFCO)1 $12,850   $12,885   0   $42,541   $24,048   77  
FFCO1 Per Share - Basic $0.27   $0.31   (13 ) $0.96   $0.57   68  
Funds From Operations (FFO)1 $13,138   $13,452   (2 ) $44,478   $26,803   66  
FFO Per Share1 - Basic $0.27   $0.32   (16 ) $1.01   $0.64   58  
Distributions $5,681   $7,576   (25 ) $28,768   $34,093   (16 )
Distributions Per Share - Basic $0.12   $0.18   (33 ) $0.65   $0.81   (20 )
Distribution Payout Ratio2 43 % 56 % (23 ) 65 % 127 % (49 )
Net (Loss) Income from Continuing Operations (NICO) $1,097   $21,405   (95 ) ($3,956 ) $21,326   (119 )
NICO Per Share - Basic $0.02   $0.51   (96 ) ($0.09 ) $0.51   (118 )
Net Income (loss) $416   $21,820   (98 ) ($1,759 ) $25,500   (107 )
Net Income (loss) Per Share - Basic $0.01   $0.52   (98 ) ($0.04 ) $0.61   (107 )
Total Assets $430,369   $367,115   17   $430,369   $367,115   17  
Working Cap. excluding assets held for sale ($29,210 ) $39,643   (174 ) ($29,210 ) $39,643   (174 )
Mortgages (assets held for sale) $5,634   $25,454   (78 ) $5,634   $25,454   (78 )
Wtd. Avg. Shares Outstanding - Basic 48,386,763   42,066,829   15   44,148,429   41,991,074   5  
Shares Outstanding 52,783,690   42,110,678   25   52,783,690   42,110,678   25  

1 Funds from Continuing Operations ("FFCO"), Funds from Continuing Operations per share, Funds from Operations ("FFO"), Funds from Operations per share and working capital (net debt) are not recognized measures under Canadian generally accepted accounting principles (GAAP). Funds from Operations is calculated by taking cash provided by operating activities on the statement of cash flows adjusted for the effect of changes in non-cash working capital and asset retirement costs incurred. Working capital (net debt) is calculated by taking current assets less current liabilities excluding the balances relating to assets held for sale. Management believes that these measures are useful supplemental measures to analyze operating performance as they demonstrate AvenEx's ability to generate the Funds from Operations necessary to fund future distributions and capital investments. AvenEx's method of calculating these measures may differ from other issuers, and accordingly, they may not be comparable to measures used by other issuers. Investors should be cautioned that these measures should not be construed as an alternative to net income, cash flow from operating activities or other measures of financial performance calculated in accordance with GAAP.

2Distribution Payout Ratio is calculated by dividing the Monthly Distributions by the Funds from Operations.



  • On December 31, 2010, AvenEx completed the conversion from an income trust to a dividend paying energy focused corporation through a plan of arrangement and amalgamation of a number of subsidiaries. The new corporation will look to provide sustainable dividends and modest growth through two core operating divisions; the Oil & Gas Division and the Elbow River Division.
  • The Corporation completed the acquisition of Great Plains Exploration Inc. ("Great Plains") for $83.6 million on November 5, 2010, through the issue of approximately 8.56 million trust units and 1.1 million exchangeable shares and the assumption of about $30.6 million in debt, working capital and transaction costs. The acquisition added approximately 1,600 BOE/day of production comprised of 60% light oil and natural gas liquids. The acquisition also provided a significant drilling inventory of oil prospects in the Cardium and Nisku formations in the Pembina and Crossfire areas and Gilwood and Slave Point zones in the Randell area.
  • Increased total proved reserves by 43% to 10.8 million BOE, and increased total proved plus probable reserves by 48% to a total of 15.3 million BOE.
  • Completed an economic contingent resource study of AvenEx's Cadomin land holdings in the Cutbank Ridge area resulting in a Best Estimate Contingent Resource of 165.5 MMCF (27.6 million BOE).
  • Oil & Gas production averaged 3,964 BOE/D for 2010 and 5,201 BOE/D for the fourth quarter of 2010.
  • Funds from Operations for 2010 were $44.5 million with a 65% distribution payout ratio.
  • AvenEx paid an initial dividend to shareholders of record on January 19, 2011 of $0.045.
  • Set a 2011 Oil & Gas Division capital spending program of $34 million with over 90% of spending directed toward oil related projects.

The Corporation's fourth quarter 2010 results exceeded management expectations as the impact of the Great Plains acquisition, higher oil prices and the normal fourth quarter seasonal increase in Elbow River results offset continued weak natural gas prices. For the year ended 2010, the Corporation had a net loss of $1.8 million, Funds from Operations of $44.5 million and distributions of 65% of Funds from Operations. For the fourth quarter 2010 the Corporation had net income of $0.4 million, Funds from Operations of $13.1 million and distributions of 43% of Funds from Operations. There were only two distributions in the quarter versus the normal three as the payout was delayed into the first quarter of 2011 because the payment was made as a dividend. Accordingly, there will be 4 dividends payments declared in the first quarter of 2011. Of the fourth quarter 2010 Funds from Operations, the Oil and Gas Division provided 74%, with 29% coming from the Elbow River Marketing Group, 2% from Real Estate and the Corporate Division used 5%. The Corporation incurred about $0.45 million in one-time costs associated with the corporate conversion and IFRS financial reporting.

In the Oil and Gas Division, fourth quarter 2010 production exceeded management expectations and averaged 5,201 BOE/D up 40% from third quarter 2010 levels of 3,719 BOE/D and up about 50% from the 3,456 BOE/D in the corresponding quarter of 2009. Quarterly production volumes were split 42% oil and NGL and 58% natural gas but 47% oil and NGL and 53% natural gas based on year end exit rate of about 5,300 BOE/D. Strong volumes from the completions and tie-ins on the Noel Cadomin natural gas projects and a number of smaller oil projects together with the oil weighted Great Plains acquisition pushed production volumes higher. Fourth quarter oil and NGL prices were $73.47 up 15% over the previous year while natural gas prices were $4.54 per MCF down 20% from the previous year level. The natural gas prices were lower despite having greater than 50% of the natural gas production hedged at prices of approximately $6.50. Prices for the year averaged $69.88 per barrel for oil and NGL and $5.29 per MCF for natural gas about 64% higher than the spot natural gas prices in the period. Given the continued weakness in the natural gas markets, the Corporation has protected its 2011 cashflow with about 25% of its natural gas production hedged at prices of above $5.75 per MCF for the year. With the Great Plains acquisition, the Oil and Gas Division increased its 2010 capital expenditures to $26 million with the fourth quarter spending primarily directed at Pembina, Randell and Peace River Arch oil opportunities and a N.E. B.C. Nikanassin natural gas test. Results for the year were very encouraging with a 43% increase in proved reserves to 10.8 MBOE and 48% increase in proved plus probable reserves to 15.3 MBOE. The 2011 capital budget has been set at $34 million with a front-end loaded 90% oil focused capital program in order to take advantage of winter access only opportunities and the current royalty drilling credit program. Although AvenEx has significant natural gas upside, natural gas development continues to be closely managed in view of current low natural gas prices.

Overall, the Elbow River Marketing Group results were slightly below normal as a relatively strong fourth quarter could not make up for very weak second and third quarters. The fourth quarter, which is usually one of Elbow River's stronger quarters, benefitted from solid propane, ethanol and heavy fuel oil sales but did not achieve prior year's levels when low inventories and cold winter weather provided an exceptional propane quarter. The fourth quarter provided Funds from Operations of about $3.8 million which were about 10% less than internal forecasts but significantly ahead of the previous quarters. The first quarter is historically one of AvenEx's stronger quarters due to Elbow River's seasonal sales cycle and the first quarter 2011 has strong early propane sales and 2011 butane and natural gasoline term sales are ahead of 2010 levels boding well for the year ahead. In addition, marketing and logistics staff has been increased in order to take advantage of opportunities across all of Elbow River's product mix.

The Corporation is continuing with the disposition of its real estate portfolio in order to focus on its Oil & Gas and Elbow River Divisions. During the fourth quarter two properties were sold, an industrial property in Ontario and the "small centre" theatre package in Western Canada. Two portfolio properties remain, an industrial property in Ontario and the "larger centre" Western Canadian theatre package. We are targeting to transact on the remaining properties in 2011. The portfolio continues to be 100% leased and perform as expected.

In the fourth quarter, AvenEx did not sell any of the EnerVest Diversified Income Trust units being held for investment purposes. The trust units currently yield approximately 8.5%, but will be disposed of as opportunities arise for the redeployment of the capital into one of AvenEx's core businesses. AvenEx continues to maintain a strong balance sheet post the Great Plains acquisition, with a debt to cashflow ratio of less than 1:1 at 0.69:1 (exclusive of mortgages), undrawn bank lines in the Oil and Gas Division and remaining mortgages of about $5.5 million in the Real Estate Division.

The Corporation paid an initial dividend of $0.045 on January 22, 2011 and monthly dividends of $0.045 are projected to be paid on the 15th of each month for 2011. The AvenEx board of directors reviews the dividend level monthly. Based on current commodity prices, tax pool balances, operational forecast and balance sheet strength the current forecast 2011 dividend payout ratio is less than 60% of Funds from Operations. This compares to a 70%-80% target distribution payout ratio of Funds from Operations when AvenEx was a Trust.

Management and directors of AvenEx wish to acknowledge the passing of our long-time friend and director William (Bill) Patterson on December 11, 2010. Bill will be sadly missed for his support, insight, quiet strength and guidance. A Chartered Accountant who was in public practice for most of his career before starting his own consulting practice and participating on a number of private and public boards. Bill had been Chairman of our Audit Committee since May 2005.


2011 will be a transition year for AvenEx with the conversion on December 31, 2010 to an energy focused dividend paying corporation from an income trust. AvenEx combines the cashflows from its Elbow River Division with those of a traditional junior oil and gas company to provide sustainable dividends and modest growth. Based on current projections, the Oil and Gas Division should provide about 70% of cashflows and Elbow River about 30%.

Like many of the junior oil and gas companies in AvenEx's peer group, 2011 for AvenEx will also continue to transition to more of an oil focus as rates of return significantly increase with higher oil prices and natural gas project returns decline with the double whammy of continued low natural gas prices and increasing costs. Capital expenditure in 2011 will be focused over 90% of spending on oil related projects while reserving natural gas projects for the future when natural gas prices increase. Production product mix looks to migrate from 45%-47% oil and natural gas liquids at the beginning of 2011 to 50%-52% oil and natural gas liquids by year end 2011. The first quarter 2011 has been a very busy quarter of capital spending as AvenEx has drilled winter access only opportunities in Randell and made a small Southern Alberta oil property acquisition from a working interest partner. Production is expected average about 5,300 BOE/D in the first quarter.

Elbow River results are traditionally stronger in the fourth and first quarters of the year due to increased seasonal demand for propane and butane. The first quarter Elbow River results look to be in line with previous normal winter quarters but not at the very high levels experienced in the first quarter of 2010 when propane sales were exceptional. For 2011, ethanol and heavy fuel sales are expected to provide greater support than past years to the core butane and propane sales.

The Corporation is moving forward with the sale of its remaining real estate assets and expects to have completed the divestiture in 2011.


Net income from continuing operations for the quarter ended December 31, 2010 was $1.1 million down 95% from $21.4 million in the quarter ended December 31, 2009, including a $4.7 million unrealized loss on financial instruments versus a $13.0 million unrealized gain at the end of the fourth quarter of 2009. Net loss from continuing operations for the year ended December 31, 2010 was $4.0 million down substantially from a net income of $21.3 million for the year ended December 31, 2009, due to the non-cash unrealized loss on financial instruments in 2010 compared to a non-cash unrealized gain in 2009. The net income for the quarter ended December 31, 2010 was $0.4 million which is down 98% versus $21.8 million for the quarter ended December 31, 2009 due to an unrealized loss on financial instruments versus an unrealized gain in the fourth quarter of 2009. Net loss for the year ended December 31, 2010 was $1.8 million compared to a $25.5 million net income for the year ended December 31, 2009 again, due to an unrealized loss on financial instruments versus an unrealized gain 2009.

Funds from continuing operations were $12.9 million for the quarter ended December 31, 2010 consistent with $12.9 million in the comparable quarter in 2009. Funds from Operations were $13.1 million for the quarter ended December 31, 2010, down 2% from Funds from Operations for the quarter ended December 31, 2009 of $13.5 million. Funds from Operations for the year ended December 31, 2010 were $44.5 million, up 66% from $26.8 million for the year ended December 31, 2009. The increase is in large part due to the first quarter 2009 losses and write-off in the Elbow River bio-diesel business.

AvenEx declared distributions of $5.7 million ($0.12 per unit) for the quarter ended December 31, 2010 which is down from the $7.6 million ($0.18 per unit) distributed for the quarter ended December 31, 2009. The 2010 fourth quarter end payout ratio was 43% of Funds from Operations compared to 56% at December 31, 2009. For the year ended December 31, 2010 monthly cash distributions of $28.8 million were lower than the $34.1 million monthly cash distributions in 2009 as the monthly distribution was reduced from $0.083 per unit to $0.06 per unit effective May 2009. The year ended December 31, 2010 distribution payout ratio was 62% of Funds from Operations lower than long term targets due to no distribution being declared at the end of December 2010. This distribution was replaced with a dividend declared on January 4, 2011, which was followed by the normal monthly dividend for January with a record date of January 31, 2011.

On December 31, 2010, Avenir Diversified Income Trust (the "Trust") effectively completed its conversion to a dividend paying corporation from an income trust pursuant to a Plan of Arrangement (the "Arrangement") under Section 193 of the Business Corporations Act (Alberta). Pursuant to the Arrangement, holders of trust units of the Trust received one common share of AvenEx for each trust unit. In addition, holders of exchangeable shares of AvenEx received common shares of AvenEx for each exchangeable shares. As a result of the Arrangement, on December 31, 2010 AvenEx had approximately 52.8 million common shares issued and outstanding.

The common shares of AvenEx trade on the Toronto Stock Exchange (the "TSX") under the trading symbol AVF. Previous historical references to "unitholders", "distributions", "trust units" and "per unit' have now been replaced by "shareholders", "dividends", "common shares" and "per share", respectively, where applicable. Despite the change in legal structure from a trust to a dividend paying corporation, AvenEx's business activities and business strategy remain unchanged and all officers and directors remain the same.



Through a combination of acquisition activity and internally generated capital expenditure programs, the Oil and Gas Division was able to increase production volumes in 2010 by 16% to 3,964 BOE/D. In comparison to the prior year, reported oil and natural gas liquids for 2010 averaged up 16% to 1,646 bbl per day while natural gas sales were up 17% to 13,909 MCF/D. As the impacts of the Great Plains corporate acquisition were realised in the fourth quarter of 2010, AvenEx achieved record production levels of 5,201 BOE/D comprised of 42% oil and natural gas liquids and 58% natural gas. This represents a 50% increase in production volumes over the fourth quarter 2009 production rate of 3,456 BOE/D. Exit rates for the Corporation in 2010 reached 5,300 BOE/D with an oil and natural gas liquids weighting of 47%.

Total gross revenue from petroleum and natural gas sales in 2010 was $69.3 million up 27% from $54.7 million in 2009 due to the increased production volumes and a 19% increase in realized oil and natural gas liquids pricing. The average price received for crude oil and natural gas liquids during the year ended December 31, 2010 was $69.88 per barrel compared $58.75 per barrel after hedging in 2009. Natural gas pricing for the twelve months of 2010 averaged $5.29 per MCF versus $5.58 per MCF in the same period of 2009 representing only a 5% decrease due to the positive impacts of hedging. In comparison to the average market spot price of $4.00 per MCF in 2010, the Corporation was able to realize a 64% premium to the spot market from both physical and financial hedging with 56% of gas sales in 2010 hedged at an average price of $6.54 per MCF. The Corporation has approximately 25% of the 2011 forecast gas sales volumes hedged at $5.78 per MCF.

For the fourth quarter of 2010, higher oil and natural gas liquids pricing helped to offset lower natural gas prices as compared to the same period of 2009. The average price received for crude oil and natural gas liquids during the fourth quarter of 2010 was $73.47 per barrel after hedging representing a 15% increase over the Q4 2009 pricing of $63.89 per barrel after hedging. Natural gas pricing for the fourth quarter of 2010 averaged $4.54 per MCF after hedging versus $5.68 per MCF in the same period of 2009 representing a decrease of 20%. Total gross revenue from petroleum and natural gas sales in the fourth quarter of 2010 was $22.7 million up 52% from the fourth quarter of 2009 at $14.9 million due mostly to the increase in sales volumes. On a BOE basis, realized pricing of $45.97 per BOE in the fourth quarter of 2010 was 1% higher than the $45.35 per BOE pricing realized in the fourth quarter of 2009.

Oil and gas operating expenses decreased 2% on a unit BOE basis in 2010 due to the addition of lower cost production from the acquisition of Great Plains completed in the fourth quarter. The total operating cost for 2010 was $23.1 million or $15.99 per BOE compared to $20.3 million or $16.31 per BOE for the twelve months of 2009. The Corporation anticipates the operating costs for 2011 to be consistent with 2010 at $16.00 per BOE.

In 2010, the Corporation participated in the drilling of 41 gross (8.8 net) wells in Alberta, British Columbia and Saskatchewan. Capital activity in 2010 was highlighted by the drilling and completion of 4 gross (1.5 net) horizontal Cadomin wells in the Noel Cutbank area of NE British Columbia. The average gross initial production rate from the new Cadomin wells in 2010 was 8,750 MCF/D of gas per well. Three of the wells were brought on stream throughout the third and fourth quarters of 2010 with the final well (17.5% working interest) having come on production in mid-March 2011. The results from these wells continue to validate the Cadomin potential on the lands controlled by AvenEx and further support the evaluation of Economic Contingent Resources for the Cutbank Ridge area as prepared by McDaniel & Associates Consultants Ltd. ("McDaniel") for year end 2010. This evaluation confirmed a Best Estimate Contingent Resource of 165.4 BCF for the Cadomin on Corporation lands in the Cutbank area. Additional details of this evaluation are contained in the management discussion and analysis section "Economic Contingent Resources for Cutbank Ridge Cadomin Formation" and the Corporation's press release of March 16, 2011.

With the acquisition of Great Plains, AvenEx also drilled an exploratory well on the Cutbank lands to test the Nikanassin formation and to fulfill the CEE commitments of Great Plains for 2010. During the fourth quarter, the Corporation drilled a vertical test well to a depth of 3,100 meters and encountered 29 meters of net pay in the Nikanassin. The well was completed by fracturing 9 of the potential 15 sand intervals and confirmed commercial gas with stabilized rates of 2,100 MCF/D of gas after a 3 day test period. The well will be placed on production in March 2011. Technical analysis of the well logs suggests a potential gas-in-place of 28 BCF of natural gas per gas spacing unit. AvenEx has Nikanassin mineral rights in approximately 20,800 net acres in the Noel Cutbank area of NE British Columbia.

In addition to the Cadomin and Nikanassin development, the Corporation continued to focus on oil projects in 2010 with the drilling of 30 gross (3.7 net) oil wells. Activity was focused on non-operated horizontal drilling activity of the Beaverhill Lake in the Deer Mountain Unit #2, the Viking of Western Saskatchewan and the Bakken in Eastern Saskatchewan. The Corporation also continued to pursue oil opportunities in the Montney in the Peace River Arch with the drilling of 3 gross (1.7 net) wells in 2010.

AvenEx continued to divest of non-core properties in 2010 in an effort to optimize the producing asset base. In total, $3.5 million of proceeds were received for assets sold with 225 MBOE of proved reserves and 130 BOE/D low netback production including significant future abandonment and reclamation liabilities. Net of the divestitures, the total capital expenditure by the Corporation on all development activities including land and seismic purchases was $26.3 million in 2010.

On November 5, 2010, AvenEx successfully closed a corporate acquisition of Great Plains. The transaction involved the Corporation purchasing 1,600 BOE/D of production comprised of 60% light oil and natural gas liquids with 3.8 million BOE of proved plus probable reserves and 103,000 net acres undeveloped land. With the acquisition, AvenEx gained a significant drilling inventory of oil prospects in the Cardium and Nisku at Pembina/Crossfire and in the Gilwood and Slave Point at Randall. Operations have commenced on the winter access property of Randell in the first quarter of 2011 with the drilling of 4 gross (3.9 net) wells. Three of the wells have been successfully completed for oil and brought on stream. The area production for Randall has increased from 150 bbl of oil per day to over 500 bbl of oil per day in March 2011.

For the year ending December 31, 2010, the Corporation produced a total of 1,447 MBOE from the asset base. The combined working interest and royalty interest proved plus probable petroleum and natural gas reserve additions from development, acquisition and divestiture activities as per the year end independent reserve report was 6,379 MBOE resulting in a 441% production replacement. Including all capital expenditures, corporate acquisitions and changes in future development costs, the Corporation booked $136.7 million in 2010 yielding an FD&A cost of $21.43 per BOE on a working interest proved plus probable basis. Included in the total year capital expenditures are land and seismic acquisitions of $20.9 million which accounted for 15% of the capital spending in 2010.

In the first quarter of 2011, AvenEx has successfully closed an asset acquisition in SE Alberta for producing oil assets in the Corporation's core area of Grand Forks. The assets have production of 110 BOE/D comprised 95% of medium grade oil and 470 MBOE of proved plus probable reserves. The assets provide high netback, low decline production with a reserve life index of 11.7 years. Based an acquisition cost of $8.9 million, AvenEx acquired the reserves for $18.94 per BOE on a proved plus probable basis and for a cash flow multiple of 5 times the forecasted 2011 net operating income of $1.75 million.

Capital investment for the Corporation in 2011 will focus almost entirely on oil development programs in the core areas of Randell, Pembina, Willesden Green and the Peace River Arch targeting the Slave Point, Cardium and Montney formations through horizontal drilling. The focus on oil will also include non-operated horizontal drilling activity in the Beaverhill Lake of Northern Alberta and the Viking of SW Saskatchewan. The gas development will be limited to 3 well tie-ins and one joint venture Cadomin well in the Noel Cutbank area. The capital programs are currently expected to be approximately $34.0 million of which 92% will be spent of oil exploitation activities. AvenEx anticipates corporate sales volumes to average between 5,100 and 5,300 BOE/D for 2011 with an average oil weighting of 50%.

Oil and Natural Gas Reserves

In accordance with NI 51-101, McDaniel prepared the McDaniel Report dated March 2, 2011, evaluating the crude oil, natural gas, natural gas liquids and sulphur reserves of the Corporation as at December 31, 2010. The tables below are a summary of the Corporation's oil, NGL and natural gas reserves and the net present value of future net revenue attributable to such reserves as evaluated in the McDaniel Report based on forecast price and cost assumptions. The information set forth below is prepared in accordance with standards contained in the Canadian Oil and Gas Evaluation Handbook (COGEH) and the reserves definitions contained in NI 51-101 and the COGEH.

Reserves Data - Forecast Prices and Costs Summary of Oil and Gas Reserves

  Gross Reserves (1)   Net Reserves(2)  
  Light               Light              
  and               and              
  Medium       Natural       Medium       Natural      
  Crude   Heavy   Gas   Natural   Crude   Heavy   Gas   Natural  
  Oil   Oil   Liquids   Gas   Oil   Oil   Liquids   Gas  
  Mbbls   Mbbls   Mbbls   Mmcf   Mbbls   Mbbls   Mbbls   Mmcf  
  Developed Producing 3,083.2   879.5   153.7   24,720.2   2,520.4   830.8   104.6   21,128.9  
  Developed Non-Producing 60.3   0.0   5.3   2,163.0   46.0   0.0   4.0   1,754.1  
  Undeveloped 368.2   0.0   16.5   10,515.2   304.8   0.0   14.2   9,037.0  
Total Proved 3,511.8   879.5   175.6   37,398.4   2,871.1   830.8   122.7   31,920.0  
Total Probable 1,608.2   215.9   81.3   15,471.6   1,223.6   199.4   52.8   11,984.6  
Total Proved plus                                
Probable(3) 5,119.9   1,095.4   256.9   52,870.1   4,094.7   1,030.1   175.5   43,904.6  


  1. Gross reserves include working interest reserves before deduction of royalties but do not include royalty interest reserves.
  2. Net reserves include working interest reserves less the deduction of royalties plus royalty interest reserves.
  3. Some totals may differ slightly due to rounding.
  4. Boe conversion ratio for natural gas of 1 Boe: 6 MCF has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not necessarily represent a value equivalency at the wellhead.

Net Present Value of Future Net Revenue of Oil and Gas Reserves(1)

  Before Future Income Tax Expenses and Discounted at  
  0 % 5 % 10 % 15 %
  (M$ ) (M$ ) (M$ ) (M$ )
Developed Producing 227,294   183,765   154,968   134,706  
Developed Non-Producing 6,659   5,733   5,034   4,490  
Undeveloped 25,652   17,117   11,535   7,699  
Total Proved 259,605   206,615   171,537   146,894  
Total Probable 133,783   85,889   60,667   45,763  
Total Proved plus Probable 393,388   292,505   232,204   192,657  

1. Estimated values do not represent fair market value.

Reserves Reconciliation

The following table sets forth a reconciliation of the Corporation's total proved, probable and proved plus probable working interest and royalty interest reserves as at December 31, 2010 against such reserves as at December 31, 2009 based on forecast price and cost assumptions.

  Total Working Interest and Royalty Interest  
   Oil Equivalent  
  Proved   Probable   Proved Plus  
  Reserves   Reserves   Probable  
Opening Balance December 31, 2009 7,675   2,828   10,503  
Extensions/Infill Drilling 1,401   609   2,010  
Improved Recovery 400   144   547  
Technical Revisions 789   (533 ) 256  
Discoveries 83   36   119  
Acquisitions 2,224   1,498   3,722  
Dispositions (206 ) (68 ) (274 )
Production (1,447 ) 0   (1,447 )
Closing Balance December 31, 2010 10,919   4,514   15,436  

Properties With No Attributed Reserves

The following table summarizes the gross and net acres of unproved properties in which the Corporation has an interest. The Corporation does not have any properties that are unproductive at this time. The following table sets out the Corporation's undeveloped land holdings as at December 31, 2010:

  Undeveloped Acres  
  Gross   Net  
Columbia 270,317   140,199  
Alberta 121,574   70,432  
Saskatchewan 22,519   9,886  
Total 414,410   220,517  

The Corporation estimates the value of this land at approximately $31.3 million based on third party evaluations effective December 31, 2010.

2010 Drilling Activity

The following table summarizes the Corporation's drilling result for the year ended December 31, 2010.

  Gross   Net  
Oil 29   3.4  
Natural Gas 8   5.0  
Coal bed methane 4   0.3  
Dry & Abandoned 0   0.0  
Total 41   8.8  

Finding and Development Costs

The following table summarizes the finding and development ("F&D") and the finding, development and acquisition ("FD&A") costs of AvenEx for 2010 and the three year average from 2008 to 2010:

  2010   Three-Year Average  
      Total       Total  
      Proved       Proved  
  Total   plus   Total   plus  
  Proved   Probable   Proved   Probable  
Finding and Development                
Explore and Develop (M$) 29,981   29,981   64,488   64,488  
Change in Future Capital (M$) 8,550   8,381   12,194   11,763  
Total (M$) 38,531   38,362   76,682   76,251  
Reserve Additions (MBOE) 2,672   2,931   4,532   4,999  
F&D Excluding Future Capital ($/BOE) 11.22   10.23   14.23   12.90  
F&D Including Future Capital ($/BOE) 14.42   13.09   16.92   15.25  
Finding, Development and Acquisition                
Explore and Develop (M$) 112,687   112,687   171,350   171,350  
Change in Future Capital (M$) 17,526   24,026   24,240   31,211  
Total (M$) 130,213   136,713   195,589   202,561  
Reserve Additions (MBOE) 4,690   6,379   8,206   10,715  
FD&A Excluding Future Capital ($/BOE) 24.03   17.67   20.88   15.99  
FD&A Including Future Capital ($/BOE) 27.76   21.43   23.83   18.90  

AvenEx calculates the FD&A costs inclusive of all exploration and development expenditures including land and seismic. Under NI 51 – 101, the methodology to be used to calculate FD&A costs includes incorporating changes in future development capital ("FDC") required to bring the proved undeveloped and probable reserves to production. For continuity, AvenEx has presented herein FD&A costs calculated both excluding and including FDC. As a result of the corporate acquisition of Great Plains and various land and seismic acquisitions in 2010, AvenEx has included the expenditure of $21 million in the FD&A analysis. In all cases, the FD&A number is calculated by dividing the identified capital expenditures by the applicable reserve additions.

Economic Contingent Resources For Cutbank Ridge Cadomin Formation

To gain a better understanding of the size and quality of the Corporation's asset base and growth potential of the Cadomin resource in the Cutbank Ridge of northeast British Columbia, AvenEx engaged McDaniel & Associates Consultants Ltd. to prepare an evaluation of the economic contingent resources for its Cutbank Ridge land holdings. The evaluation was prepared in accordance with the definitions set out under NI 51-101. The Cadomin formation in the Cutbank Ridge area is a deep basin gas resource which produces sweet natural gas from a conglomeratic sandstone reservoir ranging from 10 to 30 meters in thickness at depths of approximately 2,500 meters. AvenEx currently holds Cadomin rights in 26,000 gross acres (37 drilling spacing units) at an average working interest of 79%. These lands are contiguous with the Cutbank Ridge Cadomin play in which over 200 horizontal wells have been drilled to date. The evaluation of the AvenEx lands identifies 81 gross horizontal drilling locations in the full development scenario of this contingent Cadomin resource.

Economic contingent resources fall into three categories: low estimate (1C), best estimate (2C) and high estimate (3C). The three classifications of contingent resources have the same degree of technical certainty as the corresponding reserves categories. In determining their economic viability, the same commodity price assumptions are applied as estimating proved, probable and possible reserves. Low, best and high estimates are measures of the probability that the disclosed volumes could be exceeded. The low volume estimate is a measure whereby there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate of resources should hydrocarbons be discovered. The best volume estimate is a measure whereby there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate of resources should hydrocarbons be discovered. The high volume estimate is a measure whereby there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate of resources should hydrocarbons be discovered.

The Discovered Gas Initially In Place ("GIIP") underlying Corporation lands was evaluated at 419.5 Bcf of natural gas with the Corporation's working interest share at 338.0 Bcf of natural gas. The Low, Best and High Estimate contingent resources as of December 31, 2010 were evaluated and the Corporation share gross and net contingent resources are presented below:

Estimated Corporation Share of Economic Contingent Resources as of December 31, 2010

Classification / Level of Certainty Gross(1)   Net(2)  
  (MMcf ) (MMcf )
Low Estimate Contingent Resources 67,600   57,387  
Best Estimate Contingent Resources 165,493   135,576  
High Estimate Contingent Resources 207,440   166,529  
  1. Gross resources include the working interest contingent resources before deductions of royalties payable to others.
  2. Net contingent resources include gross resources after royalties payable to others plus royalty interest resources received.
Estimated Corporation Share of Net Present Values Before Income Taxes as of December 31, 2010 Based on Forecast Prices and Costs
  Before Tax Net Present Value (M$) (1)(2)  
Classification / Level of Certainty 0 % 5 % 10 % 15 % 20 %
Low Estimate Contingent Resources 94.1   43.8   16.3   0.4   -9.1  
Best Estimate Contingent Resources 348.3   161.5   78.4   37.1   14.9  
High Estimate Contingent Resources 541.3   250.3   128.9   70   38.2  
  1. Based on McDaniel & Associates January 1, 2011 forecast natural gas prices.
  2. Estimated values do not represent fair market value.

Contingent resources have been considered where there are contingencies that impede the commerciality of known projects with discovered resources in place. The following are considerations for commerciality that distinguish contingent resources from reserves for the Corporation's Cadomin resources:

  • Timing of Development – AvenEx does not currently have plans to fully develop the Cadomin resource within the timing set out in the McDaniel report.
  • Facility Constraints – While capacity currently exists for the peak rates defined in the McDaniel report, AvenEx cannot guarantee this capacity will exist in future years.

Discovered GIIP is defined in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") as the quantity of hydrocarbons that are estimated to be in place within a known accumulation prior to production. DGIIP is divided into recoverable and unrecoverable portions, with the estimated future recoverable portion classified as reserves and contingent resources and the remainder as at evaluation date is by definition classified as unrecoverable. Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. There is no certainty that it will be economically viable to produce any portion of the resources.

AvenEx has participated in nine horizontal Cadomin wells in the Cutbank Ridge area since 2006 to validate the resource potential on the Corporation lands. These wells have consistently met expectations with IP 30 rates averaging 5.7 MMCF of gas per day per well. AvenEx's net share in all classifications of economic contingent resources does not include the 18,900 MMCF of net proved plus probable gas reserves assigned to the Cadomin in the Corporation's December 31, 2010 reserve report.

For further information regarding AvenEx's reserves, please refer to its Annual Information Form for the year ended December 31, 2010, which is available on AvenEx's profile at www.sedar.com.


For Elbow River the fourth quarter 2010 was a marked improvement over the second and third quarters of 2010 due to the seasonal nature of their business and a strong start to the winter propane season. Quarterly cash flows of $3.8 million were slightly under expectation and below the exceptionally high $6.6 million levels of 2009 when Elbow River benefitted from both high propane and condensate/natural gasoline demand. Year to date results from ongoing operations were less than the previous year's numbers due to very strong propane results in 2009, in conjunction with a general industry decline in 2010, which negatively impacted butane demand. Also, the opening of the Southern Lights pipeline served to reduce volumes in our condensate business.

Product Review

Butane was weaker than the previous year due to reduced term and spot sales. Propane had a strong quarter on the back of cool weather and operational issues in the U.S. Northeast. YTD propane volumes were above expectations due to the strong fourth quarter demand as well as a very solid first quarter 2010 which had benefitted from a very cold winter season.

Natural gasoline was consistent with our expectations for the fourth quarter but was below the previous year due to reduced volumes during the latter half of the year resulting from the impact of the Southern Lights pipeline.

Renewables (currently exclusively ethanol) were above forecast for the quarter as a result of some niche trading opportunities and continued growth in government mandate and incentive programs.

Heavy fuel oils were approximately equal to forecast for the quarter. Lower than anticipated asphalt and fuel oil demand was offset by better than expected heavy oil profits. On an annualized basis, heavy fuel oils performed better than expected due to the increased marketing focus and the addition of heavy oil activity late in the year.

Bio-diesel Recoveries

Bio-diesel recoveries continued in the fourth quarter with approximately $0.4 million recovered and recognized in operating income. For the year $1.9 million was recovered and included in income.


Looking forward we expect Elbow River results in 2011 to be more in line with historic levels as we anticipate butane volumes to bounce back, based on initial 2011 term sales, together with steady increases in our heavy fuel oil volumes. Propane is anticipated to have a good first quarter due to strong Q1 weather demand and some trading arbitrage opportunities.


Funds from Operations decreased to $1.9 million for the year ended December 31, 2010 compared to $2.8 million for the year ended December 31, 2009. This was due to the loss in revenue resulting from the sale of the KFC portfolio in the second quarter of2010, a portion of the Landmark portfolio in the fourth quarter of 2010 and the Snidercroft building in the fourth quarter of 2010. The cash flow for the fourth quarter ended December 31, 2010 totalled $0.3 million compared to $0.6 million for the fourth quarter of 2009. There was lower income resulting from the sale of the aforementioned properties.

In 2010, the Corporation continued its program to sell the real estate assets on an individual basis and completed the sale of the following properties:

  • The KFC portfolio, a 13 property portfolio of KFC restaurants in Alberta and BC was sold in June, 2010.
  • A portion of the Landmark theatre portfolio (12 out of 15 theatres) was sold in November, 2010.
  • The Snidercroft building, a single tenant industrial building was sold in November, 2010

The balance of the portfolio continues to perform in accordance with expectations and we are pleased to report that all rents and other amounts owing from tenants throughout the balance of the portfolio continues to be paid on a timely basis. In 2011, AvenEx will continue its sales process for the balance of the assets.

The Real Estate Division had a net loss for the quarter ended December 31, 2010 of $0.7 million compared to a net income of $0.4 million for the quarter ended December 31, 2009. The decrease is a result of reduced revenue due to the sale of the properties in 2010 as well as the result of a future income tax expense of $1.3 million for the fourth quarter compared to a future income tax recovery of $0.7 million for 2009.

AvenEx Energy Corp. was created to provide stable, sustainable dividends to shareholders while providing modest growth. AvenEx is focused on energy with two distinct business units, namely Oil & Gas development and production and LPG marketing and logistics.

AvenEx trades on the TSX under the symbol AVF. For further information on AvenEx please go to our website at: www.avenexenergy.com.

This press release shall not constitute an offer to sell or the solicitation of an offer to buy the securities in any jurisdiction. The securities offered have not been and will not be registered under the United States Securities Act of 1933, as amended (the "U.S. Securities Act") or any state securities laws and may not be offered or sold in the United States except in certain transactions exempt from the registration requirements of the U.S. Securities Act and applicable state securities laws.

Forward Looking Statements

Certain statements contained herein including, without limitation, financial and business prospects and financial outlook, the effect of government announcements, proposals and legislation, plans in its Oil and Gas Division regarding hedging, wells to be drilled, expected or anticipated production rates, timing of expected production increases, the weighting of production between different commodities, expected commodity prices, exchange rates, production expenses, transportation costs and other costs and expenses, maintenance of productive capacity and capital expenditures; plans in the Elbow River Marketing Limited Partnership ("Elbow River") business regarding plans for its ongoing Liquefied Petroleum Gas ("LPG") business and activities around the exit from marketing its bio-diesel product; plans in the Real Estate Division for the timing of selling assets and the nature of capital expenditures; and the timing and method of financing these businesses, may be forward looking statements. Words such as "may", "will", "should", "could", "anticipate", "believe", "expect", "intend", "plan", "potential", "continue", "targeted" and similar expressions may be used to identify these forward looking statements. These statements reflect management's current beliefs and are based on information currently available to management. Forward looking statements involve significant risk and uncertainties. A number of factors could cause actual results to differ materially from the results discussed in the forward looking statements including, but not limited to, 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 and the inability to retain drilling rigs and other services; risks associated with its Elbow River business including, but not limited to, counterparty risk in default, operational risks, hedging, access to credit, competitor risk, seasonality and impact of the global recession on overall economic activity; and risks associated with the Real Estate Division including, but not limited to the impact the overall economy has on valuations, future delinquencies, access to mortgages and impact on interest rates; as well as the risks associated with AvenEx's incorrect assessment of the value of acquisitions, failure to realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources and the risk factors outlined under "Risk Factors" and elsewhere herein. The recovery and reserve estimates of AvenEx's reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. As a consequence, actual results may differ materially from those anticipated in 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 AvenEx 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 AvenEx 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, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which AvenEx operates; the timely receipt of any required regulatory approvals; the ability of AvenEx to obtain qualified staff, equipment and services in a timely and cost efficient manner; Divisional results; the ability of operators to operate the field in a safe, efficient and effective manner; the ability of AvenEx 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 of exploration; the timing and costs of pipeline, storage and facility construction and expansion and the ability of AvenEx 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 AvenEx operates; and the ability of AvenEx to successfully market its products, fluctuations in foreign exchange or interest rates and stock market volatility, credit risk and the ability to realize on collateral in the event of default, failure of counter parties to perform on contracts, fluctuation in the value of real property, failure to produce income or revenue from real estate, failure of tenants to meet lease obligations, increase in property taxes and mortgage, maintenance, insurance, operating costs and decreases in occupancy and rental rates, and fixed costs in relation to variable revenue streams. Readers are cautioned that the foregoing list of factors is not exhausted.

Forward looking statements and other information contained herein concerning the Oil and Gas Division, Elbow River's business, the Real Estate Division and AvenEx's general expectations concerning these industries are based on estimates prepared by each Division's management and from using data from publicly available industry sources as well as from reserve reports, market research and industry analysis and on assumptions based on data and knowledge of these industries which AvenEx believes to be reasonable. However, this data is inherently imprecise, although generally indicative of relative market positions, market shares and performance characteristics. While AvenEx is not aware of any misstatements regarding any industry data presented herein, these industries involve risks and uncertainties and are subject to change based on various factors.

These forward looking statements are made as of the date hereof and AvenEx assumes no obligation to update or review them to reflect new events or circumstances except as required by applicable securities laws.

As at December 31,        
  2010   2009  
(in thousands of dollars) $   $  
Cash 1,028   2,148  
Marketable securities 7,595   19,842  
Accounts receivable 64,658   54,831  
Prepaid expenses 3,514   8,604  
Inventory 25,591   13,687  
Risk management assets 4,950   22,825  
Assets held for sale – Real Estate 543   1,536  
  107,879   123,473  
Property and equipment 253,202   162,085  
Intangibles and other assets 12,836   9,094  
Goodwill 23,424   23,424  
Future income taxes 21,840   15,483  
Assets held for sale – Real Estate 11,188   33,556  
  430,369   367,115  
Bank indebtedness 58,380   12,300  
Accounts payable and accrued liabilities 72,705   67,063  
Distributions payable   2,527  
Risk management liabilities 5,461   404  
Liabilities of assets held for sale – Real Estate 5,862   4,460  
  142,408   86,754  
Asset retirement obligation 21,121   16,373  
Future income taxes 1,634   4,636  
Liabilities of assets held for sale – Real Estate   21,974  
  165,163   129,737  
Shareholders' equity        
Unitholders' capital   421,270  
Share capital 255,958    
Contributed surplus 7,292   8,591  
Retained earnings   120,684  
Accumulated other comprehensive income 1,956   701  
Accumulated distributions   (313,868 )
  265,206   237,378  
  430,369   367,115  
For the year ended December 31,        
  2010   2009  
(in thousands of dollars) $   $  
Oil and gas revenue 69,282   54,758  
Oil and gas transportation costs (1,754 ) (1,519 )
Royalties (9,472 ) (6,536 )
Unrealized gain (loss) on financial instruments (1,299 ) (2,136 )
Total oil and gas revenue 56,757   44,567  
Elbow River revenue 588,843   803,333  
Unrealized gain (loss) on financial instruments (22,740 ) 19,922  
Total Elbow River revenue 566,103   823,255  
Gain (loss) on sale of marketable securities 1,599   (20 )
Interest and other revenue 1,078   2,284  
Total revenue 625,537   870,086  
Oil and gas operating 23,132   20,299  
Elbow River operating 567,418   781,508  
General and administrative 17,560   21,210  
Bad debt expense (recovery) (748 ) (359 )
Foreign exchange (gain) loss 936   4,528  
Interest and bank fees 1,105   1,356  
Capital taxes 347   301  
Depletion, depreciation and amortization 25,965   23,676  
Asset retirement obligation accretion 1,291   1,095  
  637,006   853,614  
Income (loss) from continuing operations before income tax (11,469 ) 16,472  
Future income tax recovery 7,513   4,854  
Net income (loss) from continuing operations (3,956 ) 21,326  
Net income from discontinued operations – EnerVest   (607 )
Net income from discontinued operations – Real Estate 2,197   4,781  
Net income (loss) for the year (1,759 ) 25,500  
Retained earnings, beginning of year 120,684   95,184  
Elimination of retained earnings to share capital (118,925 )  
Retained earnings, end of year   120,684  
Net income (loss) from continuing operations per share        
  Basic (0.09 ) 0.51  
  Diluted (0.09 ) 0.50  
Net income from discontinued operations per share        
  Basic 0.05   0.10  
  Diluted 0.05   0.10  
Net income (loss) per share        
  Basic (0.04 ) 0.61  
  Diluted (0.04 ) 0.60  


For the year ended December 31,        
  2010   2009  
(in thousands of dollars) $   $  
Net income (loss) for the period (1,759 ) 25,500  
Change in fair value of derivative instruments designated as cash flow hedges, net of tax 592   4,930  
Change in fair value of marketable securities, net of tax 663   578  
Other comprehensive income 1,255   5,508  
Comprehensive income (loss) for the year (504 ) 31,008  
For the year ended December 31,        
  2010   2009  
(in thousands of dollars) $   $  
Net income (loss) from continuing operations (3,956 ) 21,326  
Add (deduct) non-cash items:        
  Non-cash general and administrative 1,911   1,280  
  Depletion, depreciation and amortization 25,965   23,676  
  Asset retirement obligation accretion 1,291   1,095  
  Unrealized loss (gain) on financial instruments 24,039   (17,786 )
  Unrealized foreign exchange 804   (689 )
  Future income tax recovery (7,513 ) (4,854 )
Funds from continuing operations 42,541   24,048  
Funds from discontinued operations – Real Estate 1,937   2,755  
  44,478   26,803  
Asset retirement expenditures during year (671 ) (430 )
Change in non-cash working capital (18,628 ) 127,315  
Cash provided (used in) by operating activities 25,179   153,688  
Issue of trust units, net of issue costs 2,877   683  
Repurchase of trust units   (886 )
Cash settlement of options (314 ) (61 )
Distributions to unitholders (28,768 ) (34,093 )
Increase (decrease) in bank indebtedness 46,080   (80,827 )
Real estate repayment of mortgages (614 ) (942 )
Decrease in note receivable   5,000  
Change in non-cash working capital (2,527 ) (26,228 )
Cash provided by (used in) financing activities 16,734   (137,354 )
Oil and gas property acquisitions (865 ) (9,070 )
Oil and gas property disposals 3,487   3,452  
Oil and gas development expenditures (28,913 ) (11,100 )
Acquisition of Great Plains Exploration (30,621 )  
Acquisition of Ridgeback Exploration   (22,016 )
EnerVest dispositions   603  
Purchase of Elbow River royalty (5,035 )  
Purchase of other assets (351 ) (142 )
Real estate development expenditures   (64 )
Real estate dispositions 3,801   4,231  
Change in non-cash working capital 15,505   (2,001 )
Cash provided by (used in) investing activities (42,992 ) (36,107 )
Increase (decrease) in cash during the period (1,079 ) (19,773 )
Cash, beginning of period 2,148   21,826  
Change in cash of assets held for sale (41 ) 95  
Cash, end of period 1,028   2,148  
Cash taxes paid 104   749  
Cash interest paid 1,887   3,015  

The TSX Exchange has not reviewed and does not accept responsibility for the adequacy or accuracy of this release.

Contact Information

  • AvenEx Energy Corp.
    William Gallacher
    President & CEO
    (403) 237-9949
    (403) 237-0903 (FAX)
    AvenEx Energy Corp.
    Gary H. Dundas
    Vice-President, Finance and CFO
    (403) 237-9949
    (403) 237-0903 (FAX)
    AvenEx Energy Corp.
    Suite 300, 808 - 1st Street S.W.
    Calgary, Alberta T2P 1M9