Aurora Oil & Gas reports audited fourth quarter and 2013 audited annual financial results

PERTH, Western Australia, March 21, 2014 /CNW/ - Aurora Oil & Gas Limited (TSX: AEF) (ASX: AUT) today released audited financial results for the quarter and year ended December 31, 2013. These results are unchanged from the unaudited results released on February 28, 2014. All figures are reported in US dollars unless otherwise noted.

  • Financial highlights for the 2013 year, including non-IFRS measures, compared to 2012 are:
  • Revenue US$563 million up 91%, 94% generated from liquids
  • EBITDAX US$328 million up 96%
  • Funds from operations US$273 million up 95%
  • Average daily production up 100% to approximately 21,304 boe/d (pre royalty)

Highlights for the fourth quarter of 2013, including non-IFRS measures, compared to the corresponding quarter in 2012 are:

  • Revenue US$157 million up 40%, 94% generated from liquids
  • EBITDAX US$92 million up 42%
  • Funds from operations US$76 million up 41%
  • Average daily production up 46% to approximately 24,678 boe/d (pre royalty)

  Year ended  
  Dec 31,
Dec 31,
% Change
Favourable /
(US$ thousands unless otherwise stated)      
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%
  As at As at % Change
  Dec 31,
Dec 31,
Favourable /
Weighted average common shares outstanding (million)      
  Basic 448.2 432.6 4%
  Diluted 456.4 439.4 4%
(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  
  Dec 31,
Dec 31,
% Change
Favourable /
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%
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%)
(1)     These financial measures are identified and defined below under "Non-IFRS Financial Measures"
(2)     Boe conversion is on a 6:1 basis, as explained below under "Cautionary and Forward-Looking Statements."


Aurora anticipates 2014 production of 10.6-11.7mmboe (gross) and 7.8-8.6mmboe (net), with an average daily production range of 29,000-32,000boe/d (gross) or 21,500-23,500boe/d (net). This represents a forecast 45% increase on a midpoint basis over 2013 production. To achieve this growth, the 2014 capital expenditure program is expected to be US$455-495mm, which forecast represents a modest decrease on 2013 capital expenditures for development activities. The capital program anticipates a range of US$47-49mm for drilling and completions on operated acreage, US$368-402mm for non-operated drilling and completions and US$40-44mm for facilities, land and other expenditures. The 2014 capital expenditure program includes budgeted expenditure for 49-53 net wells to be spudded and expenditure for wells under drilling and completion operations at the end of 2013. The 2014 capital expenditure program will be funded from existing cash, operating cash flows and availability under Aurora's existing bank credit facility.

As a result of this capital program Aurora expects to deliver another year of disciplined growth and consistent returns from its Sugarkane assets. The 2014 non-operated program will be the largest development program to date which together with the operational efficiencies that are being delivered by Marathon Oil EF LLC, Aurora's operating partner, is expected to result in more net wells at a lower net cost per lateral foot per well. As a result of this large program Aurora's operated activity is expected to be scaled back during 2014 to maintain a strong balance sheet and financial flexibility whilst achieving significant growth in production.

Aurora expects this strong growth to continue through 2015 and beyond through the development of the significant remaining well inventory.

The selected financial and operational information outlined above should be read in conjunction with Aurora's audited annual financial report and related Management's Discussion and Analysis for the year ended December 31, 2013, which will be filed on SEDAR and will be available for review at and on our website at Unless otherwise indicated, Aurora's audited annual financial report and 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).

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.

Cautionary and Forward-Looking Statements

Statements in this press release reflect management's expectations relating to, among other things, target dates, Aurora's expected drilling program and the ability to fund development are forward-looking statements, and can generally be identified by words such as "will", "expects", "intends", "believes", "estimates", "anticipates" or similar expressions. In addition, any statements that refer to expectations, projections or other characterizations of future events or circumstances are forward-looking statements. Statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions that some or all of the reserves described can be profitably produced in the future. These statements are not historical facts but instead represent management's expectations, estimates and projections regarding future events.

References herein to "Sugarkane" or the "Sugarkane Field" are references to the Sugarkane natural gas and condensate field within the Eagle Ford and includes the two contiguous fields designated by the Texas Railroad Commission as the Sugarkane and Eagleville Fields.

Although management believes the expectations reflected in such forward-looking statements are reasonable, forward-looking statements are based on the opinions, assumptions and estimates of management at the date the statements are made, and are subject to a variety of risks and uncertainties and other factors that could cause actual events or results to differ materially from those projected in the forward-looking statements. These factors include risks related to: exploration, development and production; oil and gas prices, markets and marketing; acquisitions and dispositions; competition; additional funding requirements; reserve estimates being inherently uncertain; changes in the rate and/or location of future drilling programs on our acreage by our operator(s), incorrect assessments of the value of acquisitions and exploration and development programs; environmental concerns; availability of, and access to, drilling equipment; reliance on key personnel; title to assets; expiration of licences and leases; credit risk; hedging activities; litigation; government policy and legislative changes; unforeseen expenses; negative operating cash flow; contractual risk; and management of growth. In addition, if any of the assumptions or estimates made by management prove to be incorrect, actual results and developments are likely to differ, and may differ materially, from those expressed or implied by the forward-looking statements contained in this document. Such assumptions include, but are not limited to, general economic, market and business conditions and corporate strategy. Accordingly, investors are cautioned not to place undue reliance on such statements.

All of the forward-looking information in this press release is expressly qualified by these cautionary statements. Forward-looking information contained herein is made as of the date of this document and Aurora disclaims any obligation to update any forward-looking information, whether as a result of new information, future events or results or otherwise, except as required by law.

Non - IFRS Financial Measures

Within this Report 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 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:

  Dec-13 Dec-12
  US$'000 US$'000
Net profit after tax 116,430  58,846
  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:

  Dec-13 Dec-12
  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 176 242
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:

  Dec-13 Dec-12
  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:

Shaun Duffy
F T I Consulting
Tel: +61 8 9485 8888 

Executive Management Contact: 
Jonathan Stewart
Executive Chairman
Tel: +61 8 9380 2700

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

Head Office
Level 1, 338 Barker Road, Subiaco, WA 6008, Australia
PO Box 20, Subiaco, WA 6904
T +61 8 9380 2700, f + 61 8 9380 2799, e

Aurora USA Oil & Gas, Inc. a subsidiary of Aurora Oil & Gas Limited
1200 Smith Street, Suite 2300, Houston TX 77002-5500
T + 1 713 402 1920, f + 1 713 357 9674

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