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
(mbbls)
|
L/M Oil (mbbls)
|
NGL and Cond (mbbls)
|
Natural Gas (mmscf)
|
BOE
(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
Net Present Values
|
Before Tax Net Present Value
(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 $3.00/boe variable component.
The well and operating cost assumptions represent a modest increase on
those used in the 2011 report. They reflect the observed costs to date
although the operator continues to advise Aurora that the 2014+ savings
will be achieved during this calendar year.
-
The drilling schedule assumes that the PUD drilling inventory is drilled
over the next 5 years with an even annual drilling schedule.
-
Forecast Commodity Pricing - The NYMEX forward strip price on 31
December 2012 has been used in the RS Report and is shown below. The
figures are then adjusted for quality, regional price variations and
further adjustments are made for the calorific value of the gas.
Year
|
Oil Price (WTI)
(US$/bbl)
|
Gas Price (Henry Hub)
(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.
SOURCE: Aurora Oil & Gas Limited