(TSX: AAV, NYSE: AAV)
Year-End 2011 Advantage Reserve Highlights
CALGARY, March 15,
2012 /PRNewswire/ - Sproule Associates Ltd. ("Sproule") was
engaged as an independent qualified reserve evaluator to evaluate
Advantage's year end reserves (the "Sproule Report") in accordance
with National Instrument 51-101 ("NI 51-101") and the Canadian Oil
and Gas Evaluation Handbook ("COGE Handbook"). The Sproule
Report includes only Advantage's 'stand-alone' reserves and
excludes the assets in Longview Oil Corp. (See "Appendix A -
Reserve Summary".) Reserves are stated on a working
interest basis unless otherwise indicated. Advantage's
year-end financial and operating information will be released on or
about March 22, 2012 and accordingly,
all references to year end 2011 financial and operating data are
estimates and are unaudited.
- Our 2011 capital program replaced 220% of production adding
18.6 mmboe of Proven & Probable ("2P") reserves at a Finding
and Development ("F&D") cost of $8.85/boe including the change in Future
Development Capital ("FDC").
- Advantage's three year corporate F&D cost of $9.90/boe (2P reserves including the change in
FDC) reflects the strong organic growth achieved at Glacier.
- Proven reserves represent 64% of total Company 2P reserves
compared to 59% in 2010 due to increasing recognition of solid well
production trends at Glacier and higher confidence in recoverable
reserves across a larger portion of our land block.
- The one year recycle ratio is 1.9x using our F&D cost of
$8.85/boe (2P reserves including the
change in FDC) and an operating netback of $17.09/boe which excludes any contributions from
Longview and commodity hedging impacts in 2011.
- Advantage's December 31, 2011 Net
Asset Value is $9.35/share at a 10%
discount rate pre-tax (includes Longview shares at market
value). The 2P Reserve Life Index ("RLI") is 26.4 years using
our estimated 2011 Q4 average production rate.
Highly Efficient Glacier 2P Reserves
Additions at F&D Cost of $7.41/boe
- Glacier reserves increased by 10% to 1.102 Tcf (183.7 mmboe) at
a F&D cost of $7.41/boe (2P
reserves including the change in FDC) and comprise 84% of total
Advantage 2P reserves.
- Glacier 2P reserve additions have been very efficient with
three year F&D cost (including the change in FDC) of
$9.03/boe.
- Proven reserves increased by 22% to 0.70 Tcf which now
represents 64% of total Glacier 2P reserves. Proven developed
producing ("PDP") reserves increased by 88% to 0.15 Tcf.
- The increase in reserves resulted primarily from Sproule's
recognition of strong production performance in both the Upper
Montney and Lower Montney formations and continued drilling
success. This led to a significant reclassification of probable to
proven reserves and an increase in the reserves assigned per well
specifically in the PDP category for the Upper Montney and for
undeveloped locations in the Lower Montney.
- The recycle ratio at Glacier is 2.4x based on 2011 F&D cost
of $7.41/boe.
- The value assigned by Sproule at Glacier is $1.175 billion as at December 31, 2011 (at a 10% discount factor
pre-tax).
- The continuing conversion of our Montney resource to higher
category reserves through delineation drilling, longer term
production performance and lower operating costs demonstrates the
repeatability and high quality of our Montney asset at
Glacier.
Phase IV Drilling Program Update
- Our Phase IV drilling program began in late July 2011 and included drilling Upper Montney
wells and "evaluation wells" to investigate additional layers of
Montney potential specifically in the Middle Montney and to test
new completion techniques in the Lower Montney.
- To date, our Phase IV drilling program has resulted in drilling
a total of 29 wells (28.5 net) of which 22 wells (21.5 net) are in
the Upper Montney, 5 wells are in the Middle Montney and 2 wells
are in the Lower Montney. As of March
15, 2012, completions and well tests have been conducted on
11 (10.5 net) Upper Montney wells and 4 Middle Montney wells. The
remaining wells will be completed and tested after spring
break-up.
- Current behind pipe volumes are estimated to be 37 mmcf/d
including wells that have been tested and existing wells that are
currently restricted as a result of our 100 mmcf/d Glacier gas
plant capacity. An additional 14 Montney wells have been
drilled and are awaiting completion.
Upper Montney Drilling Reaffirms High
Productivity & Repeatability
- As part of our Phase IV drilling program, we have completed and
tested 11 wells (10.5 net) in the Upper Montney which have extended
our delineation efforts across the Glacier land block with wells
testing the northeast, northwest and south east areas.
- Well test results have continued to demonstrate high
productivity with an average production test rate (calculated at
the end of each 90 hour flow test) of 7.8 mmcf/d at 1,100 psi
flowing pressure based on the last 11 wells (10.5 net) in the Upper
Montney. An additional 11 Upper Montney wells are awaiting
completion and testing. Some of these wells will be completed with
different completion techniques which are anticipated to further
improve well performance and reserves.
- Historical and recent production rates reaffirm the strong
production trends of the Upper Montney which have been recognized
by Sproule in their year-end 2011 reserve report.
- Since 2008, Advantage has drilled 79 gross (72.9 net) Upper
Montney wells at Glacier with the initial wells approaching 3.5
years of production history.
Middle Montney Well Tests Reveals Liquids
Potential
- To date, Advantage has drilled a total of 5 wells of which 4
wells have been completed and tested with an additional 3
recompletions undertaken in existing vertical wellbores to evaluate
the Middle Montney.
- Our evaluation wells in the Middle Montney targeted 3 potential
layers to commence vertical delineation of the thick Montney
formation at Glacier. These wells were drilled to investigate flow
potential and address the question of an appropriate "porosity
cut-off" (the minimum porosity in the rock that will contribute to
production and future reserves) in our Montney formation at
Glacier. This data is important to help calibrate the future
resource and reserves potential at Glacier.
- Natural gas test rates from the horizontal wells in the Middle
Montney were lower than anticipated, however, the natural gas
liquids ("NGL's") content was much higher than we expected. Based
on the results and geological information obtained from these
wells, we believe that our completion design was not optimal.
Additional geological and engineering work is currently underway to
refine our understanding of these layers and optimize the
completion design which we believe could improve results.
- Three vertical well recompletions were undertaken in one of the
Middle Montney layers prior to drilling our horizontal wells. The
recompletions were located across the core of our land block and
demonstrated natural gas well test rates which were comparable to
vertical wells in the Upper Montney at Glacier. Initial
reservoir pressure data indicated that this layer is approximately
35% over-pressured compared to a normal pressure gradient which is
beneficial to the potential resource/reserves per meter of
formation.
- The 4 horizontal wells drilled into the 3 Middle Montney layers
demonstrated well production test rates between 1.1 to 4.4 mmcf/d
at an average flowing pressure of 350 psi (calculated at the end of
each 90 hour flow test). Significant natural gas liquids
content was observed in the gas analyses and free condensate was
noted on flow back from 3 of the 4 wells. Liquid yields are
internally estimated to range from 25 bbls/mmcf to 50 bbls/mmcf
assuming a shallow cut refrigeration process. Liquid yields
can be increased through construction of a higher cost facility
which involves a deep cut liquids extraction process.
We estimate liquid yields would increase to the range of 57
bbls/mmcf to 90 bbls/mmcf assuming a deep cut liquids extraction
process. The propane, butane and condensate components are
estimated to comprise 46% to 60% of the liquid yield in a deep cut
liquids extraction process.
- A fifth horizontal well has been drilled and is awaiting
completion which we will conduct after re-evaluating the rock data
and completion designs.
- We believe that our low operating cost and royalty structure at
Glacier could provide significant benefits to reduce threshold
economics in support of a potential liquids rich Middle Montney
program. Several options are available for liquids processing
including undertaking modifications at our existing Glacier gas
plant, accessing the nearby Alliance pipeline which accommodates
NGL's or use of current pipeline interconnections to a third party
deep cut facility which has spare processing capacity.
- We are encouraged with our initial results in the Middle
Montney specifically with the discovery of NGL's. We caution
that we are very early in this evaluation and more delineation and
analysis will have to be undertaken in order to ascertain the
drilling economics of the three Middle Montney layers.
Lower Montney
- Two new horizontal wells have been drilled and are awaiting
completion which are expected to be conducted after spring
break-up. A comprehensive internal review of frac techniques
used in the adjacent Montney properties has been conducted and this
information will be incorporated into our completion design to
optimize the large resource potential that resides in the Lower
Montney.
- Our existing Lower Montney wells that were drilled in 2008
continue to exhibit shallow production declines and support a large
resource potential which we view as indicative of another
opportunity to grow reserves at Glacier.
Updated Glacier Montney Resource Assessment
Increases TPIIP to 10 Tcf
- Sproule was engaged to conduct an updated Montney resource
assessment for Glacier. Our initial resource assessment as of
February 28, 2009 was undertaken when
only 8 horizontal Montney wells were tested at Glacier.
Sproule's latest resource assessment includes all available
information as of February 29, 2012.
(See "Appendix B - Reserve and Resource Definitions.")
Sproule Resource Assessment Results
(All reserve and resource volumes indicated
are 'sales' except where otherwise indicated)
- Sproule's updated resource assessment dated February 29, 2012, resulted in a 320% increase in
Total Petroleum Initially In Place ("TPIP") to 10.07 Tcf gross raw
(9.33 Tcf raw AAV working interest).
- The 2P reserves plus contingent resource best estimate
increased by 90% to 2.49 TCF which represents only 27% of the
TPIIP. Our year end 2011 2P Montney reserves of 1.096 Tcf
represents only 12% of the TPIIP.
- The contingent resource assessment includes 0.61 Tcf of
resources (best estimate) in the Middle Montney which previously
had no assignment.
- Sproule also identified NGL's Initially In Place ("NGLIIP") of
156.34 million bbls and an ultimate recoverable resource best
estimate of 50.8 million bbls based on an estimated liquid yield of
32 to 40 bbls/mmcf for the Middle Montney formation.
- The following three tables summarize the results of Sproule's
updated resource assessment:
Resource Categories (AAV working interest,
Raw) (1) |
Tcf |
Total Petroleum Initially In Place (TPIIP) |
9.33 |
Discovered Petroleum Initially in Place (DPIIP)
(2) |
7.49 |
Undiscovered Petroleum Initially in Place (UPIIP)
(3) |
1.84 |
(1) |
TPIIP, DPIIP and UPIIP have been estimated using a zero percent
porosity cut-off (sandstone log scale). The Montney formation
is approximately 300 meters thick at Glacier. Sproule's analysis
identified 6 potential layers consisting of 1 layer in the Upper
Montney, 3 layers in the Middle Montney and 2 layers in the Lower
Montney. With the exception of the lowest layer in the Lower
Montney, all other layers exist across the entire Glacier land
block. |
(2) |
There is no certainty that it will be commercially viable to
produce any portion of the resources. |
(3) |
There is no certainty that any portion of the resources will be
discovered. If discovered, there is no certainty that it will be
commercially viable to produce any portion of the resources. |
Reserves & Contingent Resources (AAV
working interest, Sales) (1) (2) |
Low Estimate |
Best Estimate |
High Estimate |
Natural Gas |
|
|
|
Reserves (Tcf) (3) (4) |
0.699 |
1.096 |
1.260 |
Contingent Resources (Tcf) (5) (7) |
1.071 |
1.394 |
2.291 |
Total Reserves Plus Contingent Resources
(Tcf) |
1.770 |
2.490 |
3.551 |
Natural Gas Liquids (6) |
|
|
|
Reserves (mbbls) |
0.0 |
0.0 |
0.0 |
Contingent Resources (mbbls) (7) |
19,225 |
27,854 |
41,967 |
(1) |
All DPIIP other than cumulative production, reserves and
contingent resources have been categorized as unrecoverable. |
(2) |
Recoverable gas volumes were estimated using a 4 well per
section development in each of the 6 layers within the Montney
formation at Glacier. Recovery factors were assigned to each
layer based on the actual production performance of the Upper and
Lower Montney as reference and then adjusting the recovery factor
for each layer to reflect differing geological
characteristics. |
(3) |
Reserves have only been assigned primarily to the Upper Montney
and Lower Montney, with a nominal volume assigned to the Middle
Montney for vertical well recompletions. |
(4) |
For reserves, the Low Estimate are proved reserves, the Best
Estimate are 2P reserves and the High Estimate are 2P plus possible
reserves. Cumulative production of 52 bcf have been added to the
reserves volumes. |
(5) |
Contingent resources are assigned to the Upper Montney, Middle
Montney and Lower Montney. Contingent resources for each section
and layer were assigned if there was a sustained gas test within 2
miles of the section, otherwise, the resource was classified as
prospective undiscovered resources. |
(6) |
Liquid yields are unique to each layer and were estimated based
on the gas composition of gas samples from each layer. |
(7) |
The contingencies Sproule identified to convert contingent
resource into reserves are specific to each layer and generally
include the following : |
- Development maturity including the number of sustained well
tests and the amount of production information. Sproule
identified that even the Upper Montney is still in the early stages
of development and that not all sections have been tested at
Glacier.
- The lack of infrastructure to facilitate full development in
the short term including the required processing facilities to
extract NGL's in certain Montney layers.
- Economic contingencies dictating a slower pace of development
with current gas prices in sections that are farther from existing
gas gathering infrastructure in the Upper Montney and Lower Montney
and lower initial rates in the Middle Montney layers which may be
partially offset by higher liquid yields.
Prospective Resources (AAV working interest,
Sales) (1) (2) (3) |
Low Estimate |
Best Estimate |
High Estimate |
Natural gas (Tcf) |
0.389 |
0.578 |
0.852 |
Natural gas liquids (mbbls) |
15,616 |
22,960 |
33,526 |
(1) |
All UPIIP other than prospective resources have been
categorized as unrecoverable |
(2) |
Recoverable gas volumes were estimated using a 4 well per
section development in each of the 6 layers within the Montney
formation at Glacier. Recovery factors were assigned to each
layer based on the production performance of the Upper and Lower
Montney as reference and then adjusting each layer to reflect
differing geological characteristics. |
(3) |
Prospective resources were assigned to the Middle Montney and
Lower Montney if there were no sustained gas tests within 2 miles
of the section. |
- Our high quality asset at Glacier contains significant scope
and scale as validated by Sproule's resource assessment and is
underpinned with one of the lowest cost structures in Western Canada which provides Advantage with a
significant drilling inventory. Our recent drilling which
involved lateral and vertical delineation through the very thick
Montney formation across our contiguous land block has added
another dimension to Glacier, specifically with the Middle
Montney. We estimate that the current drilling inventory at
Glacier to be in excess of 900 wells.
- Sproule's findings confirms the considerable potential that
exists at Glacier to go significantly beyond current 2P reserves
and highlights the growth potential of our world class
unconventional Montney natural gas resource play.
Appendix A - Reserve Summary
Advantage engaged our independent qualified
reserves evaluator Sproule Associates Ltd. ("Sproule") to update
the reserves analysis for the Company in accordance with National
Instrument 51-101 and the COGE Handbook.
Reserves and production information included
herein is stated on a Company Interest basis (before royalty
burdens and including royalty interests receivable) unless noted
otherwise. This summary contains several cautionary statements that
are specifically required by NI 51-101. In addition to the detailed
information disclosed in this press release, more detailed
information on a net interest basis (after royalty burdens and
including royalty interests) and on a gross interest basis (before
royalty burdens and excluding royalty interests) will be included
in Advantage's Annual Information Form ("AIF") and will be
available at www.advantageog.com and www.sedar.com in the coming
weeks. Note that the December 31,
2010 figures below include the assets sold to Longview Oil
Corp. on April 14, 2011.
Highlights - Company Interest Reserves (Working Interests
plus Royalty Interests Receivable)
|
December 31, 2011 |
December 31, 2010 |
|
|
|
Proved plus probable reserves (mboe) |
218,386 |
244,291 |
Present Value of 2P reserves discounted at 10%, before tax
($000)(1) |
$1,483,679 |
$2,515,972 |
Net Asset Value per Share discounted at 10%, before tax
(2) |
$9.35 |
$13.63 |
Reserve Life Index (proved plus probable - years)
(3) |
26.4 |
27.5 |
Reserves per Share (proved plus probable)
(2) |
1.31 |
1.48 |
Bank debt per boe of reserves (4) |
$0.66 |
$1.18 |
Convertible debentures per boe of reserves
(4) |
$0.40 |
$0.61 |
(1) |
Assumes that development of each property will occur, without
regard to the likely availability to the Company of funding
required for that development. |
(2) |
Based on 166.304 million Shares outstanding at December 31,
2011, and 164.092 million Shares outstanding as December 31,
2010. |
(3) |
Based on Q4 average production and company interest
reserves. |
(4) |
Using boe's may be misleading, particularly if used in
isolation. In accordance with NI 51-101, a boe conversion ratio for
natural gas of 6 mcf: 1 bbl has been used which is based on an
energy equivalency conversion method primarily applicable at the
burner tip and does not represent a value equivalency at the
wellhead. Given that the value ratio based on the current price of
crude oil as compared to natural gas is significantly different
from the energy equivalency of 6:1, utilizing a conversion on a 6:1
basis may be misleading as an indication of value. |
Company Interest Reserves (Working Interests plus Royalty
Interests Receivable)
Summary as at December 31,
2011
|
|
|
Natural |
|
Oil |
|
Light & Medium Oil |
Heavy Oil |
Gas Liquids |
Natural Gas |
Equivalent |
|
(mbbl) |
(mbbl) |
(mbbl) |
(mmcf) |
(mboe) |
Proved |
|
|
|
|
|
Developed Producing |
1,458 |
19 |
2,407 |
245,879 |
44,863 |
Developed Non-producing |
38 |
- |
7 |
17,371 |
2,941 |
Undeveloped |
48 |
- |
297 |
556,097 |
93,028 |
Total Proved |
1,544 |
19 |
2,711 |
819,347 |
140,832 |
Probable |
898 |
10 |
1,177 |
452,822 |
77,554 |
Total Proved + Probable |
2,442 |
29 |
3,888 |
1,272,169 |
218,386 |
Gross Working Interest Reserves (Working
Interest only)
Summary as at December 31,
2011
|
|
|
Natural |
|
Oil |
|
Light & Medium Oil |
Heavy Oil |
Gas Liquids |
Natural Gas |
Equivalent |
|
(mbbl) |
(mbbl) |
(mbbl) |
(mmcf) |
(mboe) |
Proved |
|
|
|
|
|
Developed Producing |
1,375 |
6 |
2,374 |
244,430 |
44,493 |
Developed Non-producing |
38 |
- |
7 |
17,259 |
2,922 |
Undeveloped |
48 |
- |
297 |
556,092 |
93,027 |
Total Proved |
1,461 |
6 |
2,678 |
817,781 |
140,442 |
Probable |
870 |
5 |
1,165 |
452,262 |
77,416 |
Total Proved + Probable |
2,331 |
11 |
3,843 |
1,270,043 |
217,858 |
Present Value of Future Net Revenue using Sproule price and
cost forecasts (1)(2)
($000)
|
Before Income Taxes Discounted at
|
|
0% |
10% |
|
15% |
Proved |
|
|
|
|
Developed Producing |
$737,412 |
$476,330 |
|
$404,290 |
Developed Non-producing |
64,615 |
35,282 |
|
28,459 |
Undeveloped |
1,545,887 |
399,105 |
|
198,522 |
|
|
|
|
|
Total Proved |
2,347,914 |
910,718 |
|
631,272 |
|
|
|
|
|
Probable |
2,227,996 |
572,961 |
|
367,629 |
Total Proved + Probable |
$4,575,910 |
$1,483,679 |
|
$998,900 |
(1) |
Advantage's crude oil, natural gas and natural gas liquid
reserves were evaluated using Sproule's product price forecast
effective December 31, 2011 prior to the provision for income
taxes, interests, debt services charges and general and
administrative expenses. It should not be assumed that the
discounted future revenue estimated by Sproule represents the fair
market value of the reserves. |
(2) |
Assumes that development of each property will occur, without
regard to the likely availability to the Company of funding
required for that development. |
Sproule Price Forecasts
The present value of future net revenue at
December 31, 2011 was based upon
crude oil and natural gas pricing assumptions prepared by Sproule
effective December 31, 2011. These
forecasts are adjusted for reserve quality, transportation charges
and the provision of any applicable sales contracts. The price
assumptions used over the next seven years are summarized in the
table below:
|
|
WTI |
Edmonton Light |
Alberta AECO-C |
Henry Hub |
Exchange |
|
|
Crude Oil |
Crude Oil |
Natural Gas |
Natural Gas |
Rate |
Year |
|
($US/bbl) |
($Cdn/bbl) |
($Cdn/mmbtu) |
($US/mmbtu) |
($US/$Cdn) |
2012 |
|
98.07 |
96.87 |
3.16 |
3.55 |
1.012 |
2013 |
|
94.90 |
93.75 |
3.78 |
4.18 |
1.012 |
2014 |
|
92.00 |
90.89 |
4.13 |
4.54 |
1.012 |
2015 |
|
97.42 |
96.23 |
5.53 |
5.95 |
1.012 |
2016 |
|
99.37 |
98.16 |
5.65 |
6.07 |
1.012 |
2017 |
|
101.35 |
100.12 |
5.77 |
6.19 |
1.012 |
2018 |
|
103.38 |
102.12 |
5.89 |
6.32 |
1.012 |
Net Asset Value using Sproule price and cost
forecasts (Before Income Taxes)
The following net asset value ("NAV") table
shows what is normally referred to as a "produce-out" NAV
calculation under which the current value of the Company's reserves
would be produced at forecast future prices and costs. The value is
a snapshot in time and is based on various assumptions including
commodity prices and foreign exchange rates that vary over
time.
|
|
Before Income Taxes Discounted at |
($000, except per Share amounts) |
|
0% |
|
10% |
|
15% |
Net asset value per Share (1) -
December 31, 2010 |
|
$38.70 |
|
$13.63 |
|
$9.33 |
Present value proved and probable reserves |
|
$4,575,910 |
|
$1,483,679 |
|
$998,900 |
|
|
|
|
|
|
|
Undeveloped acreage and seismic
(2) |
|
$71,630 |
|
$71,630 |
|
$71,630 |
|
|
|
|
|
|
|
Working capital (deficit) and other |
|
(70,564) |
|
(70,564) |
|
(70,564) |
Convertible debentures |
|
(86,250) |
|
(86,250) |
|
(86,250) |
Bank debt |
|
(141,705) |
|
(141,705) |
|
(141,705) |
|
|
|
|
|
|
|
Longview shares at market value |
|
298,034 |
|
298,034 |
|
298,034 |
Net asset value - December 31, 2011 |
|
$4,647,055 |
|
$1,554,824 |
|
$1,070,045 |
Net asset value per Share (1) -
December 31, 2011 |
|
$27.94 |
|
$9.35 |
|
$6.43 |
(1) Based on 166.304 million Shares outstanding at
December 31, 2011, and 164.092
million Shares outstanding at December 31,
2010.
(2) Internal estimate
Gross Working Interest Reserves Reconciliation
|
Light & |
Heavy |
Natural Gas |
Natural |
Oil |
|
Medium Oil |
Oil |
Liquids |
Gas |
Equivalent |
Proved |
(mbbl) |
(mbbl) |
(mbbl) |
(mmcf) |
(mboe) |
Opening balance Dec. 31, 2010 |
13,862 |
1,654 |
5,181 |
736,040 |
143,371 |
Extensions |
28 |
- |
1 |
12,227 |
2,067 |
Improved recovery |
- |
- |
- |
- |
- |
Infill Drilling |
1 |
- |
8 |
15,819 |
2,645 |
Discoveries |
- |
- |
- |
- |
- |
Economic factors |
8 |
(2) |
(129) |
(19,932) |
(3,445) |
Technical revisions |
63 |
(26) |
(575) |
145,316 |
23,681 |
Acquisitions |
- |
- |
1 |
19 |
4 |
Dispositions |
(12,277) |
(1,619) |
(1,463) |
(27,756) |
(19,985) |
Production |
(224) |
(1) |
(346) |
(43,952) |
(7,896) |
|
|
|
|
|
|
Closing balance at Dec. 31, 2011 |
1,461 |
6 |
2,678 |
817,781 |
140,442 |
|
Light & |
Heavy |
Natural Gas |
Natural |
Oil |
|
Medium Oil |
Oil |
Liquids |
Gas |
Equivalent |
Proved + Probable |
(mbbl) |
(mbbl) |
(mbbl) |
(mmcf) |
(mboe) |
Opening balance Dec. 31, 2010 |
24,044 |
4,487 |
7,796 |
1,243,969 |
243,656 |
Extensions |
38 |
- |
2 |
29,346 |
4,931 |
Improved recovery |
- |
- |
- |
- |
- |
Infill Drilling |
2 |
- |
11 |
20,747 |
3,470 |
Discoveries |
- |
- |
- |
- |
- |
Economic factors |
24 |
8 |
(151) |
(20,900) |
(3,603) |
Technical revisions |
(438) |
(61) |
(1,007) |
91,631 |
13,766 |
Acquisitions |
- |
- |
1 |
27 |
5 |
Dispositions |
(21,115) |
(4,422) |
(2,463) |
(50,825) |
(36,471) |
Production |
(224) |
(1) |
(346) |
(43,952) |
(7,896) |
|
|
|
|
|
|
Closing balance at Dec. 31, 2011 |
2,331 |
11 |
3,843 |
1,270,043 |
217,858 |
Finding, Development & Acquisitions Costs
("FD&A") (1)(2)(3)
2011 FD&A Costs - Gross Working Interest Reserves excluding
Future Development Capital
|
|
Proved |
|
Proved + Probable |
Capital expenditures ($000) |
|
$202,148 |
|
$202,148 |
Acquisitions net of dispositions ($000) |
|
(547,007) |
|
(547,007) |
Total capital ($000) |
|
$(344,859) |
|
$(344,859) |
|
|
|
|
|
Total mboe, end of year |
|
140,442 |
|
217,858 |
Total mboe, beginning of year |
|
143,371 |
|
243,656 |
Production, mboe |
|
7,896 |
|
7,896 |
Reserve additions, mboe |
|
4,967 |
|
(17,902) |
|
|
|
|
|
2011 FD&A costs ($/boe) |
|
$(69.42) |
|
$19.27 |
2010 FD&A costs ($/boe) |
|
$3.47 |
|
$7.61 |
Three year average FD&A costs ($/boe) |
$(4.05) |
|
$(3.74) |
2011 F&D costs ($/boe) |
|
$8.10 |
|
$10.89 |
2010 F&D costs ($/boe) |
|
$4.60 |
|
$8.46 |
Three year average F&D costs ($/boe) |
|
$5.51 |
|
$4.23 |
NI 51-101
2011 FD&A Costs - Gross Working Interest Reserves including
Future Development Capital
|
|
Proved |
|
Proved + Probable |
Capital expenditures ($000) |
|
$202,148 |
|
$202,148 |
Acquisitions net of dispositions ($000) |
|
(547,007) |
|
(547,007) |
Net change in Future Development Capital ($000) |
|
42,053 |
|
(37,932) |
Total capital ($000) |
|
($302,806) |
|
($382,791) |
Reserve additions, mboe |
|
4,967 |
|
(17,902) |
2011 FD&A costs ($/boe) |
|
($60.95) |
|
$21.38 |
2010 FD&A costs ($/boe) |
|
$11.06 |
|
$10.89 |
Three year average FD&A costs ($/boe) |
|
$8.46 |
|
$7.51 |
2011 F&D costs ($/boe) |
|
$9.79 |
|
$8.85 |
2010 F&D costs ($/boe) |
|
$11.55 |
|
$10.97 |
Three year average F&D costs ($/boe) |
|
$13.10 |
|
$9.90 |
(1) |
Under NI 51-101, the methodology to be used to calculate
FD&A costs includes incorporating changes in future development
capital ("FDC") required to bring the proved undeveloped and
probable reserves to production. For continuity, Advantage has
presented herein FD&A costs calculated both excluding and
including FDC. |
(2) |
The aggregate of the exploration and development costs incurred
in the most recent financial year and the change during that year
in estimated future development costs generally will not reflect
total finding and development costs related to reserves additions
for that year. Changes in forecast FDC occur annually as a result
of development activities, acquisition and disposition activities
and capital cost estimates that reflect Sproule's best estimate of
what it will cost to bring the proved undeveloped and probable
reserves on production. |
(3) |
In all cases, the FD&A number is calculated by dividing the
identified capital expenditures by the applicable reserve
additions. Boes may be misleading, particularly if used in
isolation. A boe conversion ratio of 6 MCF:1 BBL is based on
an energy equivalency conversion method primarily applicable at the
burner tip and does not represent a value equivalency at the
wellhead. Given that the value ratio based on the current price of
crude oil as compared to natural gas is significantly different
from the energy equivalency of 6:1, utilizing a conversion on a 6:1
basis may be misleading as an indication of value. |
Appendix B — Reserve and Resource Definitions
Reserves are estimated remaining quantities of oil and
natural gas and related substances anticipated to be recoverable
from known accumulations, as of a given date, based on the analysis
of drilling, geological, geophysical and engineering data; the use
of established technology; and specified economic conditions, which
are generally accepted as being reasonable. Reserves are
classified according to the degree of certainty associated with the
estimates as follows:
Proved Reserves are those reserves that can be estimated
with a high degree of certainty to be recoverable. It is likely
that the actual remaining quantities recovered will exceed the
estimated proved reserves.
Probable Reserves are those additional reserves that are
less certain to be recovered than proved reserves. It is equally
likely that the actual remaining quantities recovered will be
greater or less than the sum of the estimated proved plus probable
reserves.
Possible Reserves are those additional reserves that are
less certain to be recovered than probable reserves. It is unlikely
that the actual remaining quantities recovered will exceed the sum
of the estimated proved plus probable plus possible reserves.
Resources encompasses all petroleum quantities that
originally existed on or within the earth's crust in naturally
occurring accumulations, including Discovered and Undiscovered
(recoverable and unrecoverable) plus quantities already produced.
"Total resources" is equivalent to "Total Petroleum
Initially-In-Place". Resources are classified in the following
categories:
Total Petroleum Initially-In-Place ("TPIIP") is that
quantity of petroleum that is estimated to exist originally in
naturally occurring accumulations. It includes that quantity of
petroleum that is estimated, as of a given date, to be contained in
known accumulations, prior to production, plus those estimated
quantities in accumulations yet to be discovered.
Discovered Petroleum Initially-In-Place ("DPIIP")
is that quantity of petroleum that is estimated, as of a given
date, to be contained in known accumulations prior to production.
The recoverable portion of discovered petroleum initially in place
includes production, reserves, and contingent resources; the
remainder is unrecoverable.
Contingent Resources are those quantities of petroleum
estimated, as of a given date, to be potentially recoverable from
known accumulations using established technology or technology
under development but which are not currently considered to be
commercially recoverable due to one or more contingencies.
Undiscovered Petroleum Initially-In-Place ("UPIIP") is
that quantity of petroleum that is estimated, on a given date, to
be contained in accumulations yet to be discovered. The recoverable
portion of undiscovered petroleum initially in place is referred to
as "prospective resources" and the remainder as
"unrecoverable."
Prospective Resources are those quantities of petroleum
estimated, as of a given date, to be potentially recoverable from
undiscovered accumulations by application of future development
projects.
Unrecoverable is that portion of DPIIP and UPIIP
quantities which is estimated, as of a given date, not to be
recoverable by future development projects. A portion of these
quantities may become recoverable in the future as commercial
circumstances change or technological developments occur; the
remaining portion may never be recovered due to the
physical/chemical constraints represented by subsurface interaction
of fluids and reservoir rocks.
Uncertainty Ranges are described by the Canadian Oil and
Gas Evaluation Handbook as low, best, and high estimates for
reserves and resources as follows:
Low Estimate: This is considered to be a
conservative estimate of the quantity that will actually be
recovered. It is likely that the actual remaining quantities
recovered will exceed the low estimate. If probabilistic methods
are used, there should be at least a 90 percent probability (P90)
that the quantities actually recovered will equal or exceed the low
estimate.
Best Estimate: This is considered to be the best estimate
of the quantity that will actually be recovered. It is equally
likely that the actual remaining quantities recovered will be
greater or less than the best estimate. If probabilistic methods
are used, there should be at least a 50 percent probability (P50)
that the quantities actually recovered will equal or exceed the
best estimate.
High Estimate: This is considered to be an optimistic
estimate of the quantity that will actually be recovered. It is
unlikely that the actual remaining quantities recovered will exceed
the high estimate. If probabilistic methods are used, there should
be at least a 10 percent probability (P10) that the quantities
actually recovered will equal or exceed the high estimate.
Advisory
The information in this press release
contains certain forward-looking statements, including within the
meaning of the United States Private Securities Litigation Reform
Act of 1995. These statements relate to future events or our future
intentions or performance. All statements other than statements of
historical fact may be forward-looking statements. Forward-looking
statements are often, but not always, identified by the use of
words such as "seek", "anticipate", "plan", "continue", "estimate",
"demonstrate", "expect", "may", "will", "project", "predict",
"potential", "targeting", "intend", "could", "might", "should",
"believe", "would" and similar expressions and include statements
relating to, among other things expected plans and timing of
drilling and completion of wells, expected increases and rates of
production, expected plans to expand facilities and projections
with respect to individual wells, regions, properties or projects.
These statements involve substantial known and unknown risks and
uncertainties, certain of which are beyond Advantage's control,
including: the impact of general economic conditions; industry
conditions; changes in laws and regulations including the adoption
of new environmental laws and regulations and changes in how they
are interpreted and enforced; fluctuations in commodity prices and
foreign exchange and interest rates; stock market volatility and
market valuations; volatility in market prices for oil and natural
gas; liabilities inherent in oil and natural gas operations;
uncertainties associated with estimating oil and natural gas
reserves; competition for, among other things, capital,
acquisitions of reserves, undeveloped lands and skilled personnel;
incorrect assessments of the value of acquisitions; changes in
income tax laws or changes in tax laws and incentive programs
relating to the oil and gas industry and income trusts; geological,
technical, drilling and processing problems and other difficulties
in producing petroleum reserves; and obtaining required approvals
of regulatory authorities. Advantage's actual decisions,
activities, results, performance or achievement could differ
materially from those expressed in, or implied by, such
forward-looking statements and, accordingly, no assurances can be
given that any of the events anticipated by the forward-looking
statements will transpire or occur or, if any of them do, what
benefits that Advantage will derive from them. Except as required
by law, Advantage undertakes no obligation to publicly update or
revise any forward-looking statements. For additional risk
factors in respect of Advantage and its business, please refer to
its Annual Information Form dated March 16,
2010 which is available on SEDAR at www.sedar.com
and www.advantageog.com.
References in this press release to initial
test production rates, initial "productivity", initial "flow"
rates, "90 hour flow test" and "behind pipe production" are useful
in confirming the presence of hydrocarbons, however such rates are
not determinative of the rates at which such wells will commence
production and decline thereafter. Such rates are not necessarily
indicative of long term performance or of ultimate recovery. While
encouraging, readers are cautioned not to place reliance on such
rates in calculating the aggregate production for
Advantage.
Barrels of oil equivalent (boe) may be
misleading, particularly if used in isolation. A boe conversion
ratio has been calculated using a conversion rate of six thousand
cubic feet of natural gas to one barrel. "Tcf" stands for
trillion cubic feet of natural gas and "bcf" stands for billion
cubic feet of natural gas. Such conversion rates are based on an
energy equivalency conversion method application at the burner tip
and do not represent an economic value equivalency at the wellhead.
Given that the value ratio based on the current price of crude oil
as compared to natural gas is significantly different from the
energy equivalency of 6:1, utilizing a conversion on a 6:1 basis
may be misleading as an indication of value.
The Corporation discloses several financial measures that do
not have any standardized meaning prescribed under GAAP. These
financial measures include funds from operations and cash netbacks.
Management believes that these financial measures are useful
supplemental information to analyze operating performance and
provide an indication of the results generated by the Corporation's
principal business activities prior to the consideration of how
those activities are financed or how the results are taxed.
Investors should be cautioned that these measures should not be
construed as an alternative to net income, cash provided by
operating activities or other measures of financial performance as
determined in accordance with GAAP. Advantage's method of
calculating these measures may differ from other companies, and
accordingly, they may not be comparable to similar measures used by
other companies.
Where any disclosure of reserves data is made in this press
release that does not reflect all reserves of Advantage, the reader
should note that the estimates of reserves and future net revenue
for individual properties or groups of properties may not reflect
the same confidence level as estimates of reserves and future net
revenue for all properties, due to the effects of
aggregation.
SOURCE Advantage Oil & Gas Ltd.