Aurora Oil & Gas Limited - Increase in borrowing base and mid-year reserves update

Highlights:

• Significant increase in mid-year reserves from 2012 year end reserves
• Reserves update excludes anticipated year-end drilling density determinations
• 28% increase in gross PDP reserves to 27.6 mmboe
• 18% increase in gross 1P reserves to 112.0 mmboe
• 21% increase in gross 3P reserves to 203.3 mmboe
• 50% increase in borrowing base under credit facilities to US$300 million

PERTH, Western Australia, Sept. 8, 2013 /CNW/ - Aurora Oil & Gas Limited ("Aurora") (ASX:AUT, TSX:AEF) is pleased to announce a 50% increase in the borrowing base to US$300 million available under its revolving credit facility ('Facility") and to provide a mid-year reserves update of a 28% increase in proved, developed and producing (PDP) reserves. This increase in PDP reserves during the first half of 2013 has allowed for the significant increase in the amount available under the Facility, which remains undrawn.

The estimates ("Reserves Estimates") were internally generated for the semi-annual borrowing base redetermination under the Facility. The Reserve Estimates include contributions from both the recently acquired operated acreage and existing non-operated acreage within the Sugarkane Field.

The updated gross (before royalties) Reserve Estimates are summarised in the table below:

Aurora Gross Reserves (before royalties)  as at June 30, 2013	mmboe	Increase on YE2012 Report
Proved Developed Producing (PDP)	27.6	28%
Proved (1P)	112.0	18%
Proved plus Probable (2P)	132.7	29%
Proved plus Probable plus Possible (3P)^1	203.3	21%

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¹ 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.

Additional upside anticipated in 2013 year end reserves report

Additional reserves are anticipated to be captured in the 2013 year end reserves report in relation to the non-operated acreage (19,300 net acres) within the Sugarkane Field once development plans for infill drilling of the Eagle Ford have been agreed with the operator. Further upside is also anticipated once conclusions from the ongoing downspacing pilot programs can be applied to the development of the Austin Chalk.

Key Points

The following key points should be noted when reviewing the information provided with the Reserve Estimates:

• They have been generated using data from wells commencing production after January 1, 2012. The methodology and assumptions used are consistent with those adopted by Aurora's independent engineers, Ryder Scott Company L.P., for its reserves report effective as of December 31, 2012 and disclosed earlier this year ("RS 2012 Report").
• Gross proved reserve replacement of 1H 2013 production was 490% through a combination of acquisition, transition of probable reserves and improvement in well design, and initial performance of more recent wells.
• The proved Reserve Estimates give only limited recognition of proved undeveloped reserves (PUD) 60 acre spacing within existing production units with similar well density. The 60 acre spaced wells assume a 10% reduction in estimated ultimate recovery (EUR) per well (compared to an 80 acre spaced well) due to an assumption of higher long term decline.

Reserve Estimates

The table below summarizes Aurora's Reserve Estimates generated using the forecast price and costs assumptions summarized below. See also "Cautionary and Forward Looking Statements".

Aurora reserves summary as at June 30, 2013

	Aurora Gross Reserves (before royalty interests)				Aurora Net Reserves (after royalty interests)
	L/M Oil (mbbls)	NGL and Cond (mbbls)	Natural Gas (mmscf)	BOE  (mbbls)	L/M Oil (mbbls)	NGL and Cond (mbbls)	Natural Gas (mmscf)	BOE  (mbbls)
Proved Developed Producing	10,243	11,282	36,547	27,617	7,557	8,336	27,009	20,395
Proved Undeveloped	28,380	35,826	121,608	84,384	20,931	26,501	89,530	62,353
Total Proved (1P)	38,624	47,108	157,615	112,000	28,487	34,836	116,539	82,748
Probable	8,397	6,940	32,354	20,729	6,284	5,148	24,035	15,437
Proved + Probable (2P)	47,020	54,048	189,970	132,730	34,771	39,984	140,573	98,186
Possible	-	40,941	178,023	70,612	-	30,339	132,110	52,357
Proved + Probable + Possible (3P)^2	47,020	94,989	367,993	203,341	34,771	70,323	272,683	150,542

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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.

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. 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 approximately 79,900 highly contiguous gross acres in the heart of the trend, including approximately 22,000 net acres within the Sugarkane Field in the over-pressured and liquids core 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 Michael Verm, PE, Chief Operating Officer of Aurora, who has had more than 33 years of experience in the practice of petroleum engineering. Mr. Verm consents to the inclusion in this report of the information in the form and context in which it appears.

Reserves Update Methodology and Assumptions

• Aurora generated 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). The pilot project that commenced in 2012 continues to expand to other areas of the field. Since mid-2012 wells have been drilled within Sugarkane field with horizontal separation of 500ft or less. The focus of the development plan is now shifting to areas of higher Gas to Oil Ratio ("GOR") for the 500 ft spaced wells and low GOR areas for the 330ft spaced wells.
• Similar to the RS 2012 Report, 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 GOR and well performance. The data set used to generate the type curves is taken from wells that commenced production after January 1, 2012. Whilst of a sufficient size to provide a statistically meaningful analysis, the more recent data set from the first half of 2013 captures some of the improved well performance being achieved in the field. As a result we have seen an approximate 15% improvement to type curves.
• 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 developed from the Austin Chalk production of the Weston #1H well. This is consistent with the RS 2012 Report and does not reflect any input from the recent Austin Chalk pilot program wells which commenced production in June 2013.
• Gas shrinkage and NGL yield assumptions vary by AMI but are in the range of 15% to 19% shrinkage and 110 - 134 bbls/mmscf.
• For the purpose of economic limit test:
• The well and operating cost assumptions used in the Reserves Estimates are identical to those used in the RS 2012 Report, other than well costs for the operated acreage uses a base 5,000 ft lateral well length cost of US$9.3 million (compared to US$8.1 million for the non-operated acreage).
• Forecast Commodity Pricing - The NYMEX forward strip price as at June 30, 2013 has been used in the estimate 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) (US$/bbl)	Gas Price (Henry Hub) (US$/mmbtu)
2013	$98.26	$3.72
2014	$92.14	$3.97
2015	$86.91	$4.17
2016	$83.59	$4.32
2017+	$83.59	$4.32

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

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.

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.

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 is based on the RS 2012 Report includes complete disclosure of our oil and gas reserves and other oil and gas information as at December 31, 2012 in accordance with NI 51-101, and is contained within our Annual Information Form available on our SEDAR profile at www.sedar.com.

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; 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.

SOURCE: Aurora Oil & Gas Limited

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Head Office
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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 - 06/07/2012 15:41:00