2014 Guidance - Aurora to Deliver Continued Strong Production Growth

2014 Estimated Drilling Program - Net Wells (based on the midpoint estimate of 51 net wells spud) (CNW Group/Aurora Oil & Gas Limited)

Aurora guides to an almost 50% increase in total 2014 production

  • Estimated 2014 production of 10.6-11.7 million boe (gross), 7.8-8.6 million boe (net, after royalties), 80% liquids, delivering an expected increase of ~47%(1)

  • 49-53 net wells expected to be spud in 2014, up approximately 13%(1) 

  • December 2013 exit production rate estimated at ~26,450 boe/d (gross) / 19,500 boe/d (net), an increase of 41% year on year

  • 2014 Capital expenditures of US$455 - 495 million

  • Operational efficiencies driving down costs per well

  • Capital expenditure program fully funded by existing cash, operating cash flow and availability under the existing bank credit facility

PERTH, Western Australia, Jan. 2, 2014 /CNW/ -

Full Year 2014 Guidance

Aurora Oil & Gas Limited (ASX:AUT, TSX:AEF) ("Aurora") is pleased to announce its expected 2014 production of 10.6-11.7mmboe (gross) and 7.8-8.6mmboe (net), with an average daily production range of 29,000-32,000 boe/d (gross), or 21,500-23,500 boe/d (net). This represents a forecast 47% increase over the mid-point of Aurora's guided 2013 production.

To achieve this growth, Aurora's board of directors has approved a 2014 capital expenditure program of US$455-495mm, which represents a decrease on expected 2013 capital expenditures. The capital program anticipates US$47-49mm for operated drilling and completions, 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 wells under drilling or completion operations at year end 2013. The 2014 capital expenditure program will be funded from existing cash, operating cash flows and availability under Aurora's existing bank credit facility.

Aurora forecasts between 49-53 net wells will be spud in 2014, up approximately 13% over 2013. Of that total, 3 net wells are expected to be spud on Aurora's operated acreage, and 46-50 net wells are anticipated to be spud on non-operated leases.

Aurora anticipates continued EBITDAX growth throughout 2014 and, during the second half of the year, EBITDAX should exceed capital expenditures for the same period based on the development plan reflected in today's guidance and conservative assumptions of realised commodity prices generated from a WTI oil price of $90/bbl, natural gas liquids pricing of $30/bbl per barrel and a natural gas price of $3.50/mmbtu.

(1)     As compared to the Company's most recent guidance - released on November 8, 2013

Early 2014 Operations Outlook

Due to the increased development activity undertaken in the last quarter of 2013, Aurora exited 2013 with estimated average daily production in December of approximately 26,450 boe/d (gross) / 19,500 boe/d (net), an increase of 41% from the average production rate in December 2012. This increase in development activity is expected to contribute to the continued strong growth in Aurora's production during 2014.

2014 Guidance Summary
 
    Full Year 2014
Guidance
Production      
Average Daily Production - boe/d      
  Gross 29,000   32,000
  Net 21,500   23,500
Total Volumes - mmboe      
  Gross 10.6 - 11.7
  Net  7.8 - 8.6
Capital Expenditures - US$mm  
Drilling and completions      
  Operated $47  $49 
  Non-operated $368   $402
    Total  $415  -  $451
Facilities, land, and other   $40 - $44
  Total   $455 - $495
Wells Spud - Net        
Operated   3 - 3
Non-operated  46 - 50
   Total  49 - 53

Marathon Oil Corporation, whose subsidiary, Marathon Oil EF LLC is Aurora's operating partner in the majority of its Eagle Ford interests, recently advised of its forecast 2014 capital program along with other pertinent information.  Aurora is pleased that the 2014 non-operated program will not only involve more rigs in the Sugarkane Field than in 2013, but also with the operational efficiencies that are being delivered, more net wells are forecast at a lower net cost per lateral foot per well.  The planned activity levels are readily within Aurora's cash flow and liquidity capacities.

Aurora CEO Douglas E. Brooks said: "Aurora expects to deliver another year of disciplined growth and consistent returns from its Sugarkane assets, as it is now in a low risk, high margin and repetitive development program.  Well costs have been dramatically reduced while well performance has increased even with tighter well spacing.   As such, we are confident our 2014 development drilling programs, together with the results of our ongoing downspacing in the Eagle Ford shale and future development of the Austin Chalk and Upper Eagle Ford, will deliver strong production growth during 2014. With this being Aurora's largest non-operated well development program to date in the Sugarkane Field, we anticipate scaling back our operated activity during the year to maintain a strong balance sheet and financial flexibility while achieving significant growth. We expect this strong growth to continue through 2015 and beyond through the development of our significant remaining well inventory."

For more details on Aurora's 2014 guidance, please refer to the 2014 Outlook and Guidance presentation on the Company's website at http://www.auroraoag.com.au.

Defined Reserves and Resource Terms

  • "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 liquid equivalent, unless otherwise stated.
  • "mm" prefix means million.
  • "pd" or "/d" suffix means per day.
  • "WTI" means West Texas Intermediate crude.

Cautionary and Forward Looking Statements

Statements in this press release reflect management's expectations relating to, among other things, expected annual and average daily production, 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.

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 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..

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.

Aurora presents petroleum and natural gas production and reserve volumes in barrel of oil equivalent ("boe") amounts. For purposes of computing such units, a conversion rate of 6,000 cubic feet of natural gas to one barrel of oil equivalent (6:1) is used. The conversion ratio of 6:1 is based on an energy equivalency conversion method which is primarily applicable at the burner tip and does not represent value equivalence at the wellhead. Readers are cautioned that boe figures may be misleading, particularly if used in isolation.

EBITDAX is not a financial measure prescribed by International Financial Reporting Standards ("IFRS"). Such measure is not required by, nor calculated in accordance with IFRS, and therefore is considered a Non-IFRS financial measure. 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.

 

 

 

SOURCE Aurora Oil & Gas Limited

Image with caption: "2014 Estimated Drilling Program - Net Wells (based on the midpoint estimate of 51 net wells spud) (CNW Group/Aurora Oil & Gas Limited)". Image available at: http://photos.newswire.ca/images/download/20140102_C6972_PHOTO_EN_35287.jpg

For further information:

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 info@auroraoag.com.au

Houston
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

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

Jonathan Stewart  
Executive Chairman
+61 8 9380 2700

Shaun Duffy  
FTI Consulting 
+61 8 9485 8888 
+61 404 094 384