Aurora Oil & Gas preliminary final report for year ended December 31, 2013

PERTH, Western Australia, Feb. 28, 2014 /CNW/ - Aurora Oil & Gas Limited ("Aurora") (TSX: AEF, ASX:AUT) is pleased to release its Preliminary Final Report for the year ended December 31, 2013. This report is unaudited and has been prepared in accordance with the requirements of the Australian Securities Exchange Listing Rule 4.3.A. Aurora had planned to release audited financial statements for the year ended December 31, 2013 by the end of February 2014 however additional demands and competing priorities arising out of the February 7, 2014 Baytex offer (see below) have led the Board to defer the date for finalisation of the audited financial statements.

Management expects the Company's auditors will issue an unqualified audit opinion in respect of the financial statements for the year ended December 31, 2013 which are anticipated to be finalised and released together with other usual disclosure documents in late March 2014.

The selected financial and operational information outlined below should be read in conjunction with Aurora's full Preliminary Final Report for the twelve months to December 31, 2013 which will be filed on SEDAR and will be available for review at www.sedar.com and on our website at www.auroraoag.com.au. Unless otherwise indicated, the financial information contained in this announcement has been prepared in accordance with Australian Accounting Standards ("AAS") and in compliance with International Financial Reporting Standards (IFRS).

Baytex offer
On February 7, 2014 Baytex Energy Corp announced a proposed acquisition of Aurora for A$4.10 per share. The announcement and related documents are  available through our filings on the ASX platform at www.asx.com.au, on SEDAR at www.sedar.com or can be obtained from our website at www.auroraoag.com.au.

RESULTS FOR ANNOUNCEMENT TO THE MARKET

  Year ended      
  December 31,
2013
December 31,
2012
   
  US$'000 US$'000    
  (Unaudited) (Audited)    
         
Revenue from ordinary activities 562,766  295,059  Increased 91%
Profit from ordinary activities after tax attributable to members 116,430  58,846  Increased 98%
Net profit from the period attributable to members 116,430  58,846  Increased 98%
         
Earnings per share (basic) (US cents) 25.97  13.60  Increased 91%
Net tangible assets per security (US$) 1.27  1.01  Increased 26%
         
Dividends No dividends have been paid or proposed for the year
ended December 31, 2013 (2012: Nil).

COMMENTARY ON RESULTS

Aurora Oil & Gas Limited provides the following commentary on its Appendix 4E Preliminary Final Report for the year ended December 31, 2013. Financial highlights for the 2013 year, including non-IFRS measures, compared to 2012 are:

       
  Year ended  
  December 31,
2013
December 31,
2012
% Change
Favourable /
(Unfavourable)
Financial      
Production revenue - Pre royalty 562,714  294,812  91% 
EBITDAX(1) 328,552  167,472  96% 
  Per boe - (US$/boe) 42.25  42.85  (1%)
Funds from operations(1) 273,346  139,888  95% 
  Per share - basic (US cents per share) 60.98  32.34  89% 
  Per boe - (US$/boe) 35.15  35.79  (2%)
Net profit before tax 179,418  96,202  87% 
Net profit after tax(2) 116,430  58,846  98% 
  Per share - basic (US cents per share) 25.97  13.60  91% 
  Per boe - (US$/boe) 14.97  15.06  (1%)
Adjusted net profit after tax(1) 117,412  63,044  86% 
  Per share - basic (cents per share) 26.19  14.57  80% 
Net capital expenditures (including acquisitions) 609,450  700,855  (13%)
Net capital expenditures (excluding acquisitions) 494,210  440,855  12% 
       
Operating      
Production - Pre royalties      
  Natural gas (mscf/d) 24,976  11,548  116% 
  Light/medium oil (bbls/d) 8,508  5,198  64% 
  Condensate (bbls/d) 4,859  2,034  139% 
  NGL (bbls/d) 3,774  1,522  148% 
    Total oil equivalent (boe/d) 21,304  10,678  100% 

(1) These financial measures are identified and defined below under "Non-IFRS Financial Measures".
(2) The income tax expense for the year ended December 31, 2013 of $63 million reflects the annualized
accounting deferred income tax expense for the year. No current income tax is due for payment for the
2013 year.

       
  Year ended  
  December 31,
2013
December 31,
2012
% Change
Favourable /
(Unfavourable)
Revenue derived commodity price      
  Natural gas (US$/mscf) 3.81  2.95  29% 
  Light/medium oil (US$/bbl) 99.46  99.28 
  Condensate (US$/bbl) 98.62  100.72  (2%)
  NGL (US$/bbl) 32.06  33.20  (3%)
       
Netbacks US$/boe US$/boe  
  Production revenue 72.37  75.43  (4%)
  Royalties (19.22) (19.86) (3%)
  Production taxes (2.40) (2.58) 7% 
  Operating expenses (5.41) (6.27) 14% 
  Operating netback 45.34  46.72  (3%)
       
  Depletion, depreciation and amortisation (10.76) (10.02) (7%)
  General and administrative expenses (3.08) (3.87) 20% 
  Finance costs (7.65) (7.17) (7%)
  Net profit before tax 23.07  24.61  (6%)
  Net profit after tax 14.97  15.06  (1%)

The following commentary summarises and compares the Company's significant activities and results for the year ended December 31, 2013 to those reported in the previous corresponding reporting period.

Revenue from ordinary activities
Revenue for the year ended December 31, 2013 represents the sale of light/medium oil and condensate, NGLs and natural gas from a total of 387 gross wells on production at the end of the year. Of the total gross wells that were on production at December 31, 2013, 216 wells were on production at the beginning of the year, 11 producing wells were acquired as part of the acquisition of Axle Tree and Heard Ranch properties and 160 gross new wells were brought onto production during the year.

The average daily production rate, on a boe basis, during the year ended December 31, 2013 represents an increase of 100% over the corresponding year ended December 31, 2012. The increased production rate correlates to the significant number of new wells brought on production since December 31, 2012.

The 91% increase in revenue during the year ended December 31, 2013 over the comparative year ended December 31, 2012 was a direct result of increased production. The average blended revenue derived price of US$72.37 per boe for the year ended December 31, 2013 is 4% lower than the corresponding year ended December 31, 2012, although individual commodity prices other than natural gas, were similar in the year ended December 31, 2013 to those achieved in the corresponding year .

Aurora derived 55% of its revenue for the year ended December 31, 2013 from oil sales compared to 64% in the corresponding year ended December 31, 2012. This was a result of increased NGL yields and hence a proportional increase in revenue from NGL sales and, an increase in hedging losses resulting from increased barrels of oil hedged during the current year (loss of US$2.8 million realised during the current year compared to US$0.1 million realised in year ended December 31, 2012). The increased contribution to total revenue from condensate, NGL and gas, during the current year has resulted in an overall lower blended production revenue derived price even though commodity prices, other than natural gas, remained comparable to those commodity prices experienced during the year ended December 31, 2012.

Net profit after taxation
Net profit after tax of US$116.4 million for the year ended December 31, 2013 represents a 98% increase over the year ended December 31, 2012. The increase in net profit after tax achieved during the year ended December 31, 2013 compared to the prior year is due to the increase in production resulting from an increase in the number of wells on production and the effects of the acquisition of a 100% working interest and operatorship of Axle Tree and Heard Ranches during the first quarter of 2013.

Modest increases on a per boe basis in finance costs associated with the offering of senior unsecured notes ("2020 Senior Note Offering") completed in March 2013, and depletion, depreciation and amortisation expense, due to the continuing increase in capital expenditure on new producing wells and field infrastructure, were offset by reductions in operating expenses on a per boe basis resulting from efficiencies associated with the installation of infrastructure and an oil pipeline.

Capital Expenditures

Capital expenditures during the year ended December 31, 2013 were related to the development of new wells and remediation of existing wells, installation of facilities, the acquisition of operated acreage and the procurement of equipment for both the operated and non-operated acreage. During 2013, US$115 million of capital expenditure related to the acquisition of a 100% working interest and operatorship in approximately 2,700 net acres near to or adjacent to the Sugarkane Field - the Heard and Axle Tree Ranches.

Whilst overall capital expenditure decreased by 13% from the corresponding year ended December 31, 2012, field development capital expenditure increased by 12%. The overall decrease in capital expenditure in 2013 represents fewer acquisitions undertaken compared to 2012. In 2013 a total of US$115 million was spent on acquisitions compared to US$360 million in the corresponding year.

About Aurora
Aurora is an Australian and Toronto listed oil and gas company active in the over pressured liquids rich region of the Eagle Ford Shale in Texas, United States. Aurora is engaged in the development and production of oil, condensate and natural gas in Karnes, Live Oak and Atascosa counties in South Texas.  Aurora participates in over 80,200 highly contiguous gross acres in the heart of the trend, including over 22,200 net acres within the liquids rich zones of the Eagle Ford.

Non - IFRS Financial Measures

Within this Release references are made to certain financial measures that do not have any standardized meanings prescribed by IFRS. Such measures are neither required by, nor calculated in accordance with IFRS, and therefore are considered Non-IFRS financial measures. Non-IFRS financial measures may not be comparable with the calculation of similar measures by other companies. Funds from operations, EBITDAX, net operating income, operating netback and adjusted net profit after tax are commonly used in the oil and gas industry.

EBITDAX

EBITDAX represents net income / (loss) for the period before income tax expense or benefit, gains and losses attributable to the disposal of projects, finance costs, depletion, depreciation and amortization expense, other non-cash charges, expenses or income, one-off or non-recurring fees, expenses and charges and exploration and evaluation expenses.

The following table reconciles net profit after tax to EBITDAX:

  December, 31
2013
December, 31
2012
  US$'000 US$'000
Net profit after tax 116,430  58,846 
Adjustments:    
  Share based payment expense 5,376  4,398 
  Depletion, depreciation and amortisation expense 83,632  39,161 
  Interest income (52) (247)
  Finance costs 59,493  28,027 
  Net foreign exchange loss / (gain) 346  (3,042)
  Gain on foreign currency derivatives not qualifying as hedge (1,167)
  Other income (164) (29)
  Net gain on sale of available for sale assets (770)
  Income tax expense 62,988  37,356 
  Exploration and evaluation costs 503  4,939 
EBITDAX 328,552  167,472 

Funds from Operations
Funds from operations represent funds provided by operating activities before changes in non-cash working capital. The following table reconciles net profit after tax to funds from operations:

  December, 31
2013
December, 31
2012
  US$'000 US$'000
Net profit after tax 116,430  58,846 
Add/(less) non-cash items    
  Depletion, depreciation and amortisation expense 83,632  39,161 
  Amortisation of borrowing costs and discount / premium on financial instruments 4,402  2,927 
  Share based payment expense 5,376  4,398 
  Income tax expense 62,988  37,356 
  Net foreign exchange loss / (gain) 346  (3,042)
  Employee benefit provision 172  242 
Funds from operations 273,346  139,888 

The Company considers funds from operations and EBITDAX as key measures as both assist in demonstrating the ability of the business to generate the cash flow necessary to fund future growth through capital investment. Neither should be considered as an alternative to, or more meaningful than net income or cash provided by operating activities (or any other IFRS financial measure) as an indicator of the Company's performance. Because EBITDAX excludes some, but not all, items that affect net income, the EBITDAX presented by the Company may not be comparable to similarly titled measures of other companies.

Adjusted Net Profit After Tax

Adjusted net profit after tax represents net profit after tax before non-recurring items. The following table reconciles net profit after tax to adjusted net profit after tax:

  December, 31
2013
December, 31
2012
  US$'000 US$'000
Net profit after tax 116,430  58,846 
Adjustments for non-recurring items:    
  Income tax expense - change in estimated provision for the year ended December 31, 2011 3,011 
  Gain on foreign currency derivatives not qualifying as hedges (1,167)
  Net gain on sale of available for sale assets (770)
  Exploration and evaluation costs - Eureka Energy Limited 3,124 
  Income tax expense - change in estimated provision for the year ended December 31, 2012 982 
Adjusted net profit after tax 117,412  63,044 

Management also uses certain industry benchmarks such as net operating income and operating netback to analyse financial and operating performance.

Net Operating Income
Net operating income represents net oil and gas revenue attributable to Aurora after distribution of royalty payments.

Operating Netback
Operating netback as presented, represents revenue from production less royalties, state taxes, transportation and operating expenses calculated on a boe basis. Management considers operating netback an important measure to evaluate its operational performance as it demonstrates its field level profitability relative to current commodity prices.

Defined Reserves and Resource Terms

  • "bbls" means barrels.
  • "boe" means barrels of oil equivalent and have been calculated using liquid volumes of oil, condensate and NGLs and treated volumes of gas converted using a ratio of 6 mscf to 1 bbl of liquid equivalent unless otherwise stated.
  • "scf" means standard cubic feet.
  • "m" or "M" prefix means thousand.
  • "mm" or "MM" prefix means million.
  • "NGLs" means natural gas liquids
  • "b" or "B" prefix means billion.
  • "/d" suffix means per day.

Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mscf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.  Given the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6 mscf:1 bbl, utilising a conversion ratio of 6 mscf:1 bbl may be misleading. Unless stated otherwise, all per boe references are a reference to Aurora's per boe production on a working interest basis before deduction of royalties.

SOURCE Aurora Oil & Gas Limited

For further information:

Media Contact:

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F T I Consulting
Tel: +61 8 9485 8888
Shaun.Duffy@fticonsulting.com

Executive Management Contact:

Jonathan Stewart
Executive Chairman
Tel: +61 8 9380 2700

Douglas E. Brooks
Chief Executive Officer
Tel: +1 713 402 1920