Aurora Oil & Gas Limited - Sugarkane Field Reserves Update For Debt Facility


PERTH, Western Australia, Sept. 30, 2011 /CNW/ - Aurora Oil & Gas Limited ("Aurora" or "Company") is pleased to provide the following update to its independent reserves estimate for the Company's working interests in the Sugarkane Field with an effective date of August 31, 2011.  The work has been completed by the Houston based evaluation team at Netherland, Sewell & Associates, Inc ("NSAI") at the request of the bank syndicate providing the recently announced $300m revolving reserve based debt facility.

The following net reserve allocations, after the deduction of royalty, have been made by NSAI:

  • Total proved (1P) reserves - 15.75 MMbbls of light oil, condensate and natural gas liquids ("NGLs" ) and 33.4 Bscf of natural gas.  This equates to an NPV(10) of US$ 418 million1.

  • Total proved plus probable (2P) reserves - 30.8 MMbbls of light oil, condensate and NGLs and 67 Bscf of natural gas.  This equates to an NPV(10) of US$ 718 million1.

  • On a BOE basis, these figures represent a 99% increase in the 1P reserves and a 90% increase to the 2P reserves since the last reserves update as at 31 December 2010.

This updated report is based upon 51 gross wells that were designated as either proved developed producing ("PDP") or proved developed non-producing ("PDNP") category of reserves.  In accordance with Aurora's lenders' requirements, the report only generated proved and probable reserve estimates.  Aurora intends to carry out a year end update that will consider the full reserve position.

Key points

  • The Reserves Report has been prepared in accordance with the Canadian National Instrument 51 - 101 Standards of Disclosure for Oil and Gas Activities.

  • The report continues to demonstrate the rapid transition of the Company's reserves in to the 1P and 2P categories.

  • At the effective date of the report, NSAI considers that 51 wells (9 of which are farmout wells) are in the PDP/PDNP category, 229 future well locations can be considered proved undeveloped ("PUD") and 254 future well locations are in the probable reserves category.

  • The report methodology remains consistent with the previous estimates and simply extrapolates a proved type curve across the PUD and probable well locations based on an 80 acre well spacing.

Aurora Executive Chairman and CEO Jon Stewart commented

"We are pleased with development progress and the associated impact on our reserve numbers. We consider that with 51 wells now on production within our acreage at the Sugarkane Field and a significant number of wells adjacent to the Field, the remaining risk associated with our ongoing program is now minimal.  In addition, management note that the EURs applied by NSAI are conservative relative to estimates by nearby participants in the play.  In due course we expect that additional data from more wells on production for longer periods will reconcile this position.  Finally, the limited recovery factors that these EURs and spacing assumptions generate will be addressed by tighter spacing and we remain confident that this continues to represent significant potential upside to the reserve figures."

Reserve Estimates

The following tables provide summaries of the reserve estimates generated by NSAI using forecast prices and costs.  The first shows the gross Aurora estimates, i.e. before royalty deductions, and the second shows the net Aurora estimates, i.e. post royalty deductions.

Aurora Gross Reserves
(before royalty interests)
Light and
NGLs and
Proved Developed Producing 1,332.0 1,418.1 5,479.3 3,663.3
Proved Developed Not Producing 33.8 17.1 144.2 74.9
Proved Undeveloped 6,361.3 12,142.9 39,563.4 25,098.1
Total Proved (1P) 7,727.1 13,578.1 45,186.9 28,836.4
Probable 6,759.1 13,645.7 45,249.8 27,946.4
Proved + Probable (2P) 14,486.2 27,223.8 90,436.8 56,782.8

Aurora Net Reserves
(after royalty interests)
Light and
NGLs and
Proved Developed Producing 984.1 1,049.2 4,053.8 2,708.9
Proved Developed Not Producing 24.9 12.6 106.4 55.2
Proved Undeveloped 4,684.9 8,994.3 29,287.9 18,560.5
Total Proved (1P) 5,693.9 10,056.1 33,448.1 21,324.7
Probable 4,977.4 10,117.4 33,527.6 20,682.7
Proved + Probable (2P) 10,671.3 20,173.5 66,975.6 42,007.4

The table below shows the net present value of future net revenue of the proved and probable reserves on an undiscounted basis and with a 5%, 10%, 15% and 20% discount being applied.  The undiscounted and 10% discount figures have also been provided on a post tax basis.

Net Present Values Before Tax Net Present Value ($million)
NPV(0) NPV(5) NPV(10) NPV(15) NPV(20)
Proved Developed Producing 133.8 112.3 97.9 87.6 79.7
Proved Developed Not Producing 2.1 1.6 1.2 1.0 0.8
Proved Undeveloped 630.3 440.1 319.3 238.1 181.0
Total Proved (1P) 766.1 554.0 418.4 326.6 261.5
Probable 700.1 448.1 300.1 207.9 147.6
Proved + Probable (2P) 1,466.3 1,002.1 718.6 534.5 409.1

Net Present Values After Tax Net Present Value ($million)
NPV(0) NPV(5) NPV(10) NPV(15) NPV(20)
Proved Developed Producing 102.0 90.7 82.7 76.5 71.5
Proved Developed Not Producing 1.5 1.2 0.9 0.7 0.6
Proved Undeveloped 412.8 292.1 215.0 162.4 124.7
Total Proved (1P) 516.3 384.0 298.6 239.6 196.8
Probable 457.8 283.2 184.0 123.5 84.8
Proved + Probable (2P) 974.1 667.2 482.6 363.1 281.6

The estimated future net revenue values utilized in the disclosed net present values do not necessarily represent fair market value of the Company's reserves.

Key Assumptions

NSAI used the following assumptions within their model:

  • Well cost was estimated at $7.8m for a period of 1 year and then reduced to $6.8m.  This cost estimate includes drilling, stimulating and producing of each well.

  • Operating cost of $15,000/well per month.

  • Both the Capex and the Opex costs are escalated by 2% per year

  • Forecast Commodity Pricing - NYMEX forward strip price on 31 August 2011 (the effective date of the updated reserves report) has been used and is shown below.  The figures are then adjusted for quality, transportation costs, regional price variations and further adjustments are made for the calorific value of the gas.

Year Oil Price
Gas Price
2011 89.18 4.204
2012 91.01 4.578
2013 92.13 5.055
2014 92.31 5.327
2015 92.78 5.538
Thereafter 93.30 5.735
  • The proved and probable well locations are based on 80 acre well spacing and each location has been allocated an estimated ultimate recovery ("EUR") and type curve, depending on its location within the overall field.  The type curves being applied by NSAI are summarised in the table below.

Type Curve L/M Oil
  1. < 50 bbls/mmscf
0 393 3,400 960
  1. 50 - 100 bbls/mmscf
0 416 2,495 832
  1. 100 - 500 bbls/mmscf
0 510 1,580 773
  1. 500 - 700 bbls/mmscf
330 54.6 575 480
North Longhorn 340 31.36 330 426
Excelsior 220 24.2 255 287


bbl    barrel of crude oil or natural gas liquids or condensate
scf   standard cubic foot of natural gas
barrels of oil equivalent, determined using a ratio of six Mscf of natural gas to one bbl
of condensate or crude oil
M   Prefix M indicates thousands
MM   Prefix MM indicates millions
B   Prefix B indicates billions

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 76,600 highly contiguous gross acres in the heart of the trend, including over 16,230 net acres within the liquids rich zones of the Eagle Ford.  Aurora is funded for and expects to participate in approximately 60 new development wells during 2011.

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 19 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 Statements

The Company may present 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.

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. 

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

Statements in this press release regarding 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. 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. 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.

1 NPV(10) figures are net present value of future net revenue, before income tax and discounted 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.




SOURCE Aurora Oil

For further information:

Level 20, 77 St Georges Terrace, Perth, Western Australia 6000, GPO Box 2530 Perth, Western Australia 6001, T +61 8 9440 2626, F +61 8 9440 2699, E, W

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