Aurora 2013 Year End Reserves Report

PERTH, Western Australia, Feb. 3, 2014 /CNW/ - Aurora Oil & Gas Limited ("Aurora") (ASX: AUT) (TSX: AEF) is pleased to provide a summary of its independent reserves estimate evaluation for its working interests in the Sugarkane field with an effective date of 31 December 2013. The reserve estimates were evaluated by Ryder Scott Company, L.P. ("Ryder Scott") and were prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook and in accordance with Canadian National Instrument 51 - 101 Standards of Disclosure for Oil & Gas Activities and consistent with the classification and reporting requirements of the Petroleum Resources Management System (SPE-PRMS) as required by Australian Securities Exchange Listing Rule 5 - Additional Reporting on Mining and Oil & Gas Production and Exploration Activities.

Summary

The following table summarises Aurora's gross (before royalties) reserve allocations as evaluated by Ryder Scott:

Aurora Gross Reserves (before royalties) as at 31 December 2013	mmboe	Volume increase on YE 2012 Report^1	Volume increase on Mid Year 2013 Update^1	NPV(10) US$ million (pre-tax)
Proved Developed Producing (PDP)	34.4	+96%	+53%	721
Total Proved (1P)	164.9	+82%	+54%	1,845
Proved + Probable (2P)	223.8	+125%	+74%	2,309
Proved + Probable + Possible (3P)^2	272.2	+67%	+38%	2,514

Key Points

The following key points should be noted when reviewing the information provided with these reserve estimates:

• PDP reserves comprise 79% liquids.
• Increase in proved reserves primarily based on 40 acre spacing development across most of the Sugarkane field
• Proved reserve replacement of approximately 1000% during the year through a combination of:
• 40 acre spacing;
• Acquisition of Sugarkane operated assets; and
• Continued improvements in well production performance.

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¹ Calculation of the production increase percentages above includes allowance for 2013 production of 7.76mmboe (before royalties).
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 2013 evaluated by Ryder Scott using forecast prices and costs contained in their report dated 31 January 2014 ("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

Reserve Classification	Aurora Gross Reserves (before royalty interests)						Aurora Net Reserves (after royalty interests)
	Cond (mmbbl)	NGL (mmbbl)	Subtotal NGL/Cond (mmbbl)	L/M Oil (mmbbl)	Natural Gas (Bcf)	BOE (mmbbl)	Cond (mmbbl)	NGL (mmbbl)	Subtotal NGL/Cond (mmbbl)	L/M Oil (mmbbl)	Natural Gas (Bcf)	BOE (mmbbl)
Proved Developed Producing	6.7	6.5	13.1	14.1	42.9	34.4	4.9	4.8	9.7	10.4	31.7	25.4
Proved Developed Non-Producing	0.0	0.0	0.0	0.6	0.2	0.7	0.0	0.0	0.0	0.5	0.2	0.5
Proved Undeveloped	37.1	27.5	64.6	34.4	184.8	129.8	27.4	20.2	47.6	25.3	136.3	95.6
Total Proved (1P)	43.8	34.0	77.8	49.1	227.9	164.9	32.3	25.1	57.4	36.2	168.1	121.5
Probable	16.3	14.6	31.0	11.6	98.3	58.9	12.1	10.8	23.0	8.6	73.0	43.8
Proved + Probable (2P)	60.2	48.6	108.8	60.7	326.2	223.8	44.4	35.9	80.3	44.8	241.0	165.3
Possible	19.4	13.0	32.3	1.4	87.8	48.4	14.3	9.5	23.8	1.0	64.4	35.5
Proved + Probable + Possible (3P)^3	79.6	61.5	141.1	62.1	414.0	272.2	58.7	45.4	104.1	45.8	305.4	200.8

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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 before tax 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.

Table 2: Net Present Value before tax⁴

Reserve Category	Before Tax Net Present Value (US$million)
	NPV(0)	NPV(5)	NPV(10)	NPV(15)	NPV(20)
Proved Developed Producing	1,079	857	721	629	564
Proved Developed Non-Producing	28	25	23	21	20
Proved Undeveloped	2,610	1,645	1,101	766	546
Total Proved (1P)	3,717	2,527	1,845	1,416	1,130
Probable	1,143	702	464	324	233
Proved + Probable (2P)	4,860	3,229	2,309	1,740	1,363
Possible	701	371	205	111	55
Proved + Probable + Possible (3P)	5,561	3,600	2,514	1,851	1,418

Type Curve Methodology

• Incorporated a number of type curves areas which were created based upon various gas to oil ratios, different fluid types, historical production performance and comparisons of operated and non-operated areas.
• Based on wells placed on production over the past 18 months, generated a type curve for each reserve classification for each area using statistical analysis, assuming 80 acre nominal spacing. Then applied a spacing dependant recovery factor percentage reduction ranging from 9% to 30% to all wells in units to be developed on less than 80 acre spacing.
• Applied adjustments to the type curves for lateral lengths and number of stages per well.
• The reference point for the volumes produced is at the point of sale. Gas shrinkage and NGL yield assumptions by AMI and operated assets are applied as appropriate.  The gas shrinkages range from 17% to 25% and the NGL yields range from 96 to 136 bbls/mmscf.

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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. See Aurora's AIF for after-tax present values of future net revenue attributed to Aurora's reserves.

Assumptions

EAGLE FORD

Aurora's proved reserves development plan is based on predominantly 330 ft horizontal separation between wells and lateral well lengths of between 4,000 and 8,000 ft. (Note: a 5,000 ft lateral length well which is located 330 ft horizontally from an offset well, results in an approximate 40 acre spacing pattern).

The proved reserves for the Eagle Ford formation include wells on existing 40 acre or greater units (as indicated by the operator's analysis of spacing performance) using the proved type curves by type curve area. The proved reserves include 386 existing producing wells, two wells awaiting production and 853 proved undeveloped locations.

The proved and probable development plan includes 70 wells that are located on the regulatory unit boundary and are subject to dual unit approvals.  Approximately 2% of Aurora's Sugarkane acreage remains undeveloped and is not included in this reserve evaluation.  It is expected that this acreage will eventually be unitized and developed. Probable reserves include 13 Aurora operated wells which are expected to be drilled, but due to planned lateral lengths, would include third party acreage, requiring pooling agreements.  All the wells in the proved plus probable cases include the probable type curve for each of the areas as described in the type curve methodology above.

The possible reserve category includes two 30 acre pilot units comprising nine wells with further evaluation plans during 2014.  Additionally, eight wells which require pooling with third parties are included in this category.

Well distribution for reserve classification is shown in the table below.

EAGLE FORD GROSS WELLCOUNT SUMMARY
RESERVE CATEGORY	Proved Developed Producing	Proved Developed Non-Producing	Proved Undeveloped	Probable	Possible	TOTAL
WELLCOUNT	386	2	853	83	17	1341

AUSTIN CHALK

Aurora's development plan for the Austin Chalk horizon covers all or parts of the Axle Tree ranch on its operated acreage and all or parts of the Longhorn, Sugarloaf and Ipanema AMI's on its non-operated acreage.  The plan is based on 60 acre spacing, utilizing two Austin Chalk type curves developed by analysing the various oil-gas ratios.   The proven reserves include the existing five Austin Chalk producing wells plus 19 proven undeveloped locations which lie within three drillsite locations of the Austin Chalk producing wells.

The probable reserves comprise 162 well locations which are adjacent to the proved reserve locations within the Austin Chalk development area.

Possible reserves comprise 159 wells in the northern portion of the Sugarloaf and Longhorn AMI's which are based on current geological interpretation.

AUSTIN CHALK GROSS WELLCOUNT SUMMARY
RESERVE CATEGORY	Proved Developed Producing	Proved Undeveloped	Probable	Possible	TOTAL
WELLCOUNT	5	19	162	159	345

PEARSALL

Possible reserves have been assigned to the Pearsall formation within formed units that hold approximately 35 wells, based upon 160 acre spacing, located generally within the Excelsior and Longhorn AMI's.

WELL COSTS

Well costs are based on estimates provided by the operator of Aurora's non-operated acreage, together with internally generated estimates for its operated acreage. These estimates are then adjusted for horizontal well lengths accordingly.  In general the well costs are based on a nominal 5,000 ft lateral design with a drill and complete cost of US$7.5 million.   This results in well costs ranging from US$6.7 million to US$10.5 million depending on location, depth, lateral length and artificial lift design.

The drilling schedule assumes the inventory will be drilled over the next five years with a varying number of wells each year.

FORECAST COMMODITY PRICING

The NYMEX forward strip price on 31 December 2013 (the effective date of the updated reserves report) has been used and is shown below.  The figures are then adjusted for quality and regional price variations. Further adjustments are made for the calorific value of the gas.

Year	Oil Price (US$/bbl)	Gas Price (US$/MMbtu)
2014	$93.19	$3.56
2015	$92.36	$4.03
2016	$90.26	$4.23
2017	$88.29	$4.42
Thereafter	$86.88	$4.63

NGL pricing has been assumed at 30% of WTI pricing.

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. Aurora 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 80,200 highly contiguous gross acres in the heart of the trend, including over 22,200 net acres within the liquids rich zones of the Eagle Ford.   Aurora recently announced an approximate 14,000 net acre position in the Eaglebine play of East Texas.   No reserves have been assigned to that acreage as of this report.

Technical information contained in this report in relation to the Sugarkane field was compiled by Aurora from information sourced from its operated assets and provided by the project operator for non-operated assets and reviewed by Michael L. Verm, BSc, Chief Operating Officer of Aurora, who has had more than 30 years' 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.

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.

Aurora's reserve estimates as presented in this document are constructed using a deterministic method based upon an anticipated development schedule. Future well locations have been designated to reserve categories based on their likelihood to be drilled.

Reported reserves represent the aggregation of reserves from lower risk categories, for example our 3P reserves represent the arithmetic sum of our proved, probable and possible reserves. Reserve replacement ratios presented herein for a reserve category are calculated by (a) subtracting the difference of the total reserves in that category as at December 31, 2012 and total production in 2013 from the total reserves in that category as at December 31, 2013, and (b) dividing that difference by total production in 2013.

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. 

There is no assurance that the forecast prices and cost assumptions will be attained and variances could be material. The recovery and reserve estimates of our reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein. Our oil and gas reserves statement for the year ended December 31, 2013, 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; 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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