Aurora Year End Reserves Report - Effective 31 December 2012

PERTH, Australia, Jan. 31, 2013 /CNW/ - Aurora Oil & Gas Limited ("Aurora") 
(ASX:AUT, TSX:AEF) is pleased to provide details of the independent reserves 
estimates for Aurora's working interests in the Sugarkane Field with an 
effective date of 31 December 2012. The reserve estimates were prepared by 
the Houston based team of Ryder Scott Company, L.P. ("Ryder Scott") in 
accordance with the standards contained in the Canadian Oil and Gas Evaluation 
Handbook and with the reserve definitions contained in Canadian National 
Instrument 51 - 101 - Standards of Disclosure for Oil & Gas Activities. 
The following gross (before royalties) Aurora reserve allocations have been 
estimated by Ryder Scott: 


    --  Total proved developed producing (PDP) of 21.6 mmboe,
        comprising 77% liquids, with a pre-tax NPV(10) of US$501
        million (a 360%(1) increase on previous report).
    --  Total proved (1P) reserves of 94.7 mmboe and a pre-tax NPV(10)
        of US$1,007 million (a 23%(1) increase on previous report).
    --  Total proved plus probable (2P) reserves of 102.9 mmboe and a
        pre-tax NPV(10) of US$1,051 million (a 16%(1) increase on
        previous report).
    --  Total proved plus probable plus possible (3P) reserves(2) of
        167.7 mmboe and a pre-tax NPV(10) of US$1,362 million (a 38%(1)
        increase on previous report).

Key Points

The following key points should be noted when reviewing the information 
provided with these reserve estimates:
    --  Proved reserve replacement of 380% through a combination of
        acquisition, transition of probable reserves and improvement in
        type curves.
    --  Limited recognition of 60 acre spacing around pilot well
        locations with only a 10% reduction in EUR due to the
        assumption of a higher long term decline.

______________________________
(1) Calculation includes allowance for 2012 production.
(2) Possible reserves are those reserves that are less certain to be recovered 
than probable reserves. There is a 10% probability that the quantities 
actually recovered will be equal or exceed the sum of the proved plus probable 
plus possible reserves.

Reserve Estimates

The following tables provide summaries of the reserve estimates as at 31 
December 2012 generated by Ryder Scott using forecast prices and costs 
contained in their report dated 28 January 2013 ("RS Report"). See "Cautionary 
and Forward Looking Statements" below for a statement of principal assumptions 
and risks that may apply.

Table 1: Aurora reserves summary

 ___________________________________________________________________________
|           |      Aurora Gross Reserves    |       Aurora Net Reserves     |
|           |   (before royalty interests)  |    (after royalty interests)  |
|___________|_______________________________|_______________________________|
|           |       |NGL and|Natural|       |       |NGL and|Natural|       |
|           |L/M Oil| Cond  | Gas   |  BOE  |L/M Oil| Cond  | Gas   |  BOE  |
|           |(mbbls)|(mbbls)|(mmscf)|(mbbls)|(mbbls)|(mbbls)|(mmscf)|(mbbls)|
|___________|_______|_______|_______|_______|_______|_______|_______|_______|
|     Proved|       |       |       |       |       |       |       |       |
|  Developed|       |       |       |       |       |       |       |       |
|  Producing| 7,752 | 8,778 |30,133 |21,552 | 5,710 | 6,490 |22,258 |15,909 |
|___________|_______|_______|_______|_______|_______|_______|_______|_______|
|     Proved|       |       |       |       |       |       |       |       |
|Undeveloped|23,694 |30,656 |112,722|73,137 |17,436 |22,653 |83,263 |53,967 |
|___________|_______|_______|_______|_______|_______|_______|_______|_______|
|Total      |       |       |       |       |       |       |       |       |
|Proved (1P)|31,446 |39,433 |142,855|94,688 |23,146 |29,143 |105,522|69,876 |
|___________|_______|_______|_______|_______|_______|_______|_______|_______|
|   Probable| 1,433 | 3,595 |18,915 | 8,181 | 1,069 | 2,677 |14,091 | 6,094 |
|___________|_______|_______|_______|_______|_______|_______|_______|_______|
|Proved +   |       |       |       |       |       |       |       |       |
|Probable   |       |       |       |       |       |       |       |       |
|(2P)       |32,879 |43,028 |161,769|102,869|24,215 |31,820 |119,612|75,970 |
|___________|_______|_______|_______|_______|_______|_______|_______|_______|
|   Possible| 2,436 |36,702 |154,182|64,835 | 1,793 |27,166 |114,285|48,006 |
|___________|_______|_______|_______|_______|_______|_______|_______|_______|
|Proved +   |       |       |       |       |       |       |       |       |
|Probable + |       |       |       |       |       |       |       |       |
|Possible   |       |       |       |       |       |       |       |       |
|(3P)(3)    |35,315 |79,731 |315,952|167,705|26,008 |58,986 |233,897|123,976|
|___________|_______|_______|_______|_______|_______|_______|_______|_______|

Totals may not sum due to rounding.

_______________________________
(3) Possible reserves are those reserves that are less certain to be recovered 
than probable reserves. There is a 10% probability that the quantities 
actually recovered will be equal or exceed the sum of the proved plus probable 
plus possible reserves.

The table below shows the net present value of future net revenue of Aurora's 
reserves on an undiscounted basis and with a 5%, 10%, 15% and 20% discount 
being applied on a before tax basis.

Table 2: Net Present Value (4)

 _____________________________________________________________________
|                   |               Before Tax Net Present Value      |
|Net Present Values |                       (US$million)              |
|                   |_________________________________________________|
|                   |  NPV(0) |  NPV(5) | NPV(10) | NPV(15) | NPV(20) |
|___________________|_________|_________|_________|_________|_________|
|   Proved Developed|         |         |         |         |         |
|          Producing|   801.5 |   606.7 |   500.7 |   434.1 |   388.0 |
|___________________|_________|_________|_________|_________|_________|
| Proved Undeveloped| 1,512.5 |   845.1 |   506.2 |   311.4 |   189.5 |
|___________________|_________|_________|_________|_________|_________|
|Total Proved (1P)  | 2,314.0 | 1,451.8 | 1,006.9 |   745.5 |   577.5 |
|___________________|_________|_________|_________|_________|_________|
|           Probable|   141.3 |   75.3  |   44.0  |   26.9  |   16.5  |
|___________________|_________|_________|_________|_________|_________|
|Proved + Probable  |         |         |         |         |         |
|(2P)               | 2,455.2 | 1,527.2 | 1,050.9 |   772.3 |   594.0 |
|___________________|_________|_________|_________|_________|_________|
|           Possible| 1,133.5 |   552.1 |   308.0 |   183.3 |   112.0 |
|___________________|_________|_________|_________|_________|_________|
|Proved + Probable +|         |         |         |         |         |
|Possible (3P)(5)   | 3,588.8 | 2,079.3 | 1,358.9 |   955.6 |   706.0 |
|___________________|_________|_________|_________|_________|_________|

______________________________ 
(4) NPV(10) figures are net present value of future net revenue, before income 
tax and discount at 10%. The estimated future net revenue values utilized in 
the disclosed net present values do not necessarily represent the fair market 
value of Aurora's reserves
(5) Possible reserves are those reserves that are less certain to be recovered 
than probable reserves. There is a 10% probability that the quantities 
actually recovered will be equal or exceed the sum of the proved plus probable 
plus possible reserves.

Methodology and Assumptions
    --  Production during 2012 totalled 3.91 mmboe before royalties and
        2.88 mmboe after royalties.
    --  Aurora provided Ryder Scott with a proved development plan
        across all of the Sugarkane Field that is predominantly based
        on 660ft horizontal separation and well lengths between 4,000
        and 8,000ft. (Note: a 5,000ft lateral is equivalent to 80 acre
        spacing with 660ft horizontal separation between well bores). 
        During 2012 a number of spacing pilot program wells were
        drilled with separations of 500ft and 350ft.  Within the units
        where these wells have been drilled, the development plan
        assumes pilot well spacing on a similar spacing where unit
        geometry allows. In the proved and probable cases there are a
        total of 44 units out of the 174 units that Aurora participates
        in where increased well density has been assumed.  The
        development plan honours all of the proposed unit boundaries
        and conforms to both lease and legislative obligations and
        makes no assumptions about further optimisation that may occur
        to increase well density in the other units. In the proved case
        this equates to 785 gross (182 net) well locations of which 220
        locations are now on production.  It is likely that further
        optimisation on land will be achieved over time which will
        allow more efficient placement of down spaced wells.
    --  Type curves were constructed for multiple areas within the
        Sugarkane field and applied to future well locations with
        adjustments for variations in horizontal length and well
        spacing.  The different type curve areas were delineated on the
        basis of variations in Gas to Oil Ratio ("GOR") and well
        performance.  (Further details on the type curves are provided
        below.)  The Ryder Scott probable profile generates an EUR that
        remains 30% below the expectation estimates provided by the
        field operator for 5,000ft laterals.
    --  The probable and possible reserves estimate considers an Austin
        Chalk development across approximately half of the acreage
        (covering parts of Longhorn, Sugarloaf and Ipanema Areas of
        Mutual Interest) on a 160 acre spacing and using a type curve
        taken from the Austin Chalk production in the Weston #1H well. 
        This generates an additional 151 gross (44.5 net) well
        locations which are allocated as 25 wells in the probable
        category and 126 well locations in the possible category.
    --  The possible reserve estimates also include 76 gross well
        locations in the Pearsall Shale.  This utilises a type curve
        that has been generated from offset operator production data
        and assumes 360 acre spacing.  This reserve category also
        captures the increment associated with a reduced terminal
        decline for the Eagle Ford profile that has been observed in
        older wells that have had artificial lift installed.
    --  Well costs are based on estimates provided by the operator and
        adjusted for horizontal well length.  Estimates of future cost
        reductions are consistent with ongoing and planned cost
        initiatives.  The following well costs were used by Ryder Scott
        in the RS Report:

 _______________________________________________
| Well Length |         2013   |        2014+   |
|_____________|________________|________________|
|   5,000 ft  |  $8.9 million  |  $7.8 million  |
|_____________|________________|________________|
    --  Operating costs for the proved reserves comprised of a
        $7,000/well/month fixed component and a $4.00/boe variable
        component, with the probable and possible reserve categories
        assuming a $6,000/well/month fixed component and a $3.00/boe
        variable component.
        The well and operating cost assumptions represent a modest
        increase on those used in the 2011 report.  They reflect the
        observed costs to date although the operator continues to
        advise Aurora that the 2014+ savings will be achieved during
        this calendar year.
    --  The drilling schedule assumes that the PUD drilling inventory
        is drilled over the next 5 years with an even annual drilling
        schedule.
    --  Forecast Commodity Pricing - The NYMEX forward strip price on
        31 December 2012 has been used in the RS Report and is shown
        below.  The figures are then adjusted for quality, regional
        price variations and further adjustments are made for the
        calorific value of the gas.

 ___________________________________________________
|   Year  | Oil Price (WTI) | Gas Price (Henry Hub) |
|         |    (US$/bbl)    |      (US$/mmbtu)      |
|_________|_________________|_______________________|
|   2013  |        $93.19   |             $3.56     |
|_________|_________________|_______________________|
|   2014  |        $92.36   |             $4.03     |
|_________|_________________|_______________________|
|   2015  |        $90.26   |             $4.23     |
|_________|_________________|_______________________|
|   2016  |        $88.29   |             $4.42     |
|_________|_________________|_______________________|
|  2017+  |        $86.88   |             $4.63     |
|_________|_________________|_______________________|

NGL pricing has been assumed at 30% of the WTI oil pricing above.

Type Curves

In order to generate the reserve estimates for the Sugarkane Field in the RS 
Report, a complex analysis involving multiple type curves, variations for well 
length and well spacing were used by Ryder Scott to generate the type curves 
applied to future well locations within the field development plan.

To provide further detail, Aurora has prepared the following plots and 
tabulated results to show an average type curve for the gas condensate and 
high GOR oil windows using the same data and methodology utilized by Ryder 
Scott in the RS Report, but over a wider area and applied to a normalised 
5,000 ft lateral. As such this internal analysis replicates the historical 
conservative approach adopted by Ryder Scott for the RS Report.

 _______________________________________________________________
|                             | Gas Condensate |  High GOR Oil  |
|_____________________________|________________|________________|
|              EUR (mboe)     |         655    |         546    |
|_____________________________|________________|________________|
|  Percentage (Crude/NGL/Gas) |      48/18/34  |      70/12/18  |
|_____________________________|________________|________________|
|Initial Production (boe/d)(6)|  1,020 - 1,522 |   761 - 1,158  |
|_____________________________|________________|________________|
|   30 day average (boe/d)(6) |   730 - 1,096  |     506 - 875  |
|_____________________________|________________|________________|
|   60 day average(boe/d)(6)  |     597 - 989  |     385 - 699  |
|_____________________________|________________|________________|

The boe figures in the table and charts assumed an NGL yield of 91 - 117 
bbls/mmscf depending on location in the field.

_______________________________
(6) These figures are taken from a statistical analysis of the production data 
used by Ryder Scott. The range represents the Q1 to Q3 or P25 to P75 
distribution of the each data set.

About Aurora
Aurora is an Australian and Toronto listed oil and gas company active 
exclusively in the over pressured liquids rich region of the Eagle Ford shale 
in Texas, United States. The company 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 77,000 highly 
contiguous gross acres in the heart of the trend, including over 19,100 net 
acres within the liquids rich zones of the Eagle Ford.

Technical information contained in this report in relation to the Sugarkane 
field was compiled by Aurora from information provided by the project operator 
and reviewed by I L Lusted, BSc (Hons), SPE, a Director of Aurora who has had 
more than 20 years experience in the practice of petroleum engineering. Mr. 
Lusted consents to the inclusion in this report of the information in the form 
and context in which it appears.

Cautionary and Forward Looking Statements

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.

Unless otherwise stated, all evaluations of future net revenue in this release 
are after deduction of royalties, development costs, production costs, local 
taxes and well abandonment costs but before consideration of indirect costs 
such as administrative, overhead and other miscellaneous expenses.

Our oil and gas reserves statement for the year ended December 31, 2012, which 
will include complete disclosure of our oil and gas reserves and other oil and 
gas information in accordance with NI 51-101, will be contained within our 
Annual Information Form which will be available on our SEDAR profile at 
www.sedar.com when filed.

Numbers in the tables above may not add due to rounding.

Statements in this press release which 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" and "resources" 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 and resource estimates 
being inherently uncertain; 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. 

Aurora Oil & Gas Limited ABN 90 008 787 988 HEAD OFFICE Level 20, 77 St. 
Georges Terrace, Perth, WA 6000, Australia GPO Box 2530 Perth, WA 6001, 
Australia t +61 8 9440 2626, f +61 8 9440 2699, einfo@auroraoag.com.au  
HOUSTON Aurora USA Oil & Gas, Inc. a subsidiary of Aurora Oil & Gas Limited 
1111 Louisiana, Suite 4550, Houston, TX 77002 USA t +1 713 402 1920, f +1 713 
357 9674 www.auroraoag.com.au

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Image available at:  
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Image with caption: "High GOR Region (CNW Group/Aurora Oil & Gas Limited)". 
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SOURCE: Aurora Oil & Gas Limited

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CO: Aurora Oil & Gas Limited
NI: OIL 

-0- Jan/31/2013 02:28 GMT


 
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