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) reserves2 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
(before royalty interests)
Aurora Net Reserves
(after royalty interests)
  L/M Oil (mbbls) NGL and Cond (mbbls) Natural Gas (mmscf) BOE
L/M Oil (mbbls) NGL and Cond (mbbls) Natural Gas (mmscf) BOE
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

Net Present Values Before Tax Net Present Value
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) 
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 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. 

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

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

SOURCE: Aurora Oil & Gas Limited

For further information:

Aurora Oil & Gas Limited ABN 90 008 787 988
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, e

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

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