Solid Drilling Results at Glacier Leads to Record Reserve Additions and
Production Gains
(TSX: AAV, NYSE: AAV)
CALGARY, March 8 /CNW/ - Advantage Oil and Gas Ltd. ("Advantage" or "the Company") is pleased to announce its year end reserves as of December 31, 2009. Sproule Associates Ltd. ("Sproule") was engaged as an independent qualified reserve evaluator to evaluate Advantage's year-end reserves in accordance with National Instrument 51-101 and the COGE handbook (the "Sproule Report"). Year end financial and operating information will be released on or about March 16, 2010 and accordingly, all references to year end 2009 financial and operating data are estimates and are unaudited.
Highlights
- Replaced 698% of 2009 annual production at an all-in FD&A cost of
$10.14/boe.
- Capital development program added 95.9 mmboe at a F&D cost of
$9.82/boe.
- Current production capability including new well tests at Glacier
exceeds 90 mmcfd.
- Glacier development on-track to reach production target of 50 mmcfd
in second quarter of 2010.
- Advantage's Net Asset Value ("NAV") per share increased 7.4% in 2009
to $15.07/share at a 10% discount factor, before tax.
Reserves Continuity Schedule - Working Interest Reserves
- The following table summarizes the changes in Advantage's proven and
probable ("P+P") reserves for the year ended December 31, 2009 and
the costs associated with these changes:
Change
In Future
Development
Capital
Total Capital Net of
P+P Expend- Alberta
Working itures/ Drilling Total
Interest Disposition Incen- Total Capital
Reserves Proceeds tives(1) Capital per boe
(mboe) ($ 000) ($ 000) ($ 000) ($/boe)
Reserves
December 31,
2008 173,418
----------
Development
program 95,880 $170,868 $770,346 $941,214 $9.82
Dispositions (27,205) $(245,150) - $(245,150) $(9.01)
---------- ---------- ---------- ---------- ----------
Reserve
additions 68,675 $(74,282) $770,346 $696,064 $10.14
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
Production (9,829)
----------
Reserves
December 31,
2009 232,264
----------
----------
(1) The Sproule Report includes Alberta Deep Royalty Incentives of
$117.4 million and Alberta Drilling Incentives of $21.9 million (the
"Alberta Drilling Incentives")
- Overall the Company replaced 698% of 2009 production with the vast
majority of reserve additions attributable to our Montney resource
drilling and development program at Glacier, Alberta.
- Net Corporate reserve additions amounted to 68.7 mmboe at an all-in
cost of $10.14/boe.
- Our development program resulted in total additions of 95.9 mmboe at
a cost of $9.82/boe including the change in Future Development
Capital ("FDC") net of Alberta Drilling Incentives.
- These additions were partially offset by reserve dispositions which
reduced reserves by 27.2 mmboe with net proceeds of $245.1 million or
$9.01/boe.
- Advantage's December 31, 2009 Net Asset Value per share ("NAV") is
$15.07/share at a 10% discount rate before tax calculated using the
Sproule Report and price forecasts. Our NAV increased by 7.4% from
2008 as the increase in reserves more than offset the significant
decline in Sproule's natural gas price forecast.
- The one year recycle ratio is 2.6 times using the finding,
development and acquisition ("FD&A") cost of $10.14/boe including the
change in FDC and our 2009 operating netback of $26.36/boe.
- The proven and probable reserves life index ("RLI") increased by 86%
from 2008 to 28.2 years using our estimated fourth quarter 2009
average production rate. The RLI is anticipated to decline as
production increases associated with our Phase II Glacier development
program come on-stream during the second quarter of 2010.
Glacier Montney Overview
- Advantage acquired its initial position at Glacier in 2007 as part of
the Sound Energy Trust acquisition. At December 31, 2009, Advantage
has invested approximately $234.2 million at Glacier for drilling,
completions, facility construction and additional land acquisitions.
The majority of these expenditures have been directed toward drilling
and completion activities to evaluate the quality and extent of the
Montney formation in our land block which consists of 84 gross (80
net) sections at December 31, 2009. A total of 10 gross (9.3 net)
vertical wells and 42 gross (34 net) horizontal wells have been
drilled which have resulted in significant P+P reserve additions
across our land block.
- Optimization of drilling and completion practices combined with
improved geological knowledge at Glacier have significantly increased
the horizontal well test rates and reduced costs to date as outlined
in the following table:
Upper Montney - Average Test Results and Cost Analysis
First 12 Hz wells Last 16 Hz wells(1)
Test Rate (mmcfd) 3.6 6.5
Flowing pressure (psi) 704 1,253
Rate per frac (mmcfd per frac)(2) 465 802
Number of fracs per well 8 12
Completion cost per frac
($ million) $0.43 $0.25
Drilling & completion cost
per well ($million) $6.0 $4.6
(1) Number of fracs, completion cost per frac and drilling and completion
cost per well based on Advantage's last 8 operated wells
(2) Due to testing equipment constraints on high rate/high pressure
wells, the rate per frac has been adjusted to a common flowing
pressure of 435 psi for comparative purposes.
- Since October 2009, a total of 16 gross (12 net) horizontal wells
have been drilled and production tested in the Upper Montney which
have indicated test rates ranging from 3.1 to 10.6 mmcfd with
stronger flowing pressures compared to prior wells which tested
between 1.2 to 5.5 mmcfd. An additional 5 gross (5 net) have been
drilled and will be completed and tested as ground conditions permit.
- We have increased the number of fracs per horizontal well and have
optimized drilling and completion techniques to improve cost
efficiencies. Additionally, our financial flexibility has allowed us
to capitalize on the current lower cost environment.
- On the west side of our Glacier land block, a new Upper Montney
horizontal well in February 2010 was tested at 10.4 mmcfd at 2,179
psi flowing pressure which represents the best well we have tested to
date. A second Upper Montney well on the same drilling pad, tested at
10.6 mmcfd at a flowing pressure of 1,782 psi.
Lower Montney
- Advantage has drilled and completed a total of 7 gross (4.4 net)
Lower Montney horizontal wells since 2007. Test rates on these wells
have averaged 2.2 mmcfd per well with the two most recent Advantage
wells in January and March 2010 testing at 4.6 mmcfd at 917 psi and
4.2 mmcfd at 495 psi.
- We are encouraged by the Lower Montney results to date but believe
that as additional wells are drilled in the future, frac design
optimization and improved technical knowledge on rock quality will
improve results.
- The Lower Montney qualifies for the Alberta Deep Royalty Incentive
which provides royalty credits of up to approximately $3.2 million
per well and significantly enhances the drilling economics by
offsetting a significant portion of the costs of a horizontal well.
Glacier Reserves
- Advantage's extensive drilling and development program has resulted
in a 284% increase in reserves assigned by Sproule in the Upper and
Lower Montney at Glacier from 35.8 mmboe (0.21 Tcf) to 137.4 mmboe
(0.82 Tcf) at December 31, 2009. The value assigned by Sproule
increased by 290% from $0.3 billion as at December 31, 2009 to $1.17
billion as at December 31, 2009 at a 10% discount factor before tax.
- Capital expenditures at Glacier amounted to $132.5 million in 2009
which included the completion of Phase I of our development program
in May 2009 resulting in the achievement of 25 mmcfd of production.
Additional expenditures through the balance of 2009 included the
commencement of our Phase II development program which included
drilling 27 gross (19.4 net) horizontal wells and the expansion of
gathering systems and facilities to increase production capacity to
50 mmcfd by the second quarter of 2010.
- The following table provides a breakdown on the Montney assumptions
related to the undeveloped reserves at Glacier included in the
Sproule Report:
Montney Undeveloped P+P Reserves Summary
Upper Lower
Montney Montney Total
Number of future locations (gross/net) 181/170 62/53 243/223
Working Interest reserves assigned (bcf) 634 135 769
Future Development Capital including
facilities ($million) $1,002 $305 $1,308
Alberta Drilling Incentives ($million) $(61.4) $(76.6) $(138)
-------- -------- --------
Net capital cost ($million) $941 $229 $1,170
-------- -------- --------
-------- -------- --------
Net capital cost/boe ($/boe) $8.90 $10.15 $9.12
Net capital cost/well ($million) $5.5 $4.3 $5.2
Average reserves/net well (bcf) 3.7 2.6 3.4
Average Initial Production Rate/well
(mmcf/d) 3.5 2.5 3.3
- Sproule's forecast includes gross capital of $1.3 billion ($1.17
billion net capital including Alberta Drilling Incentives) for
undeveloped reserves at Glacier which includes the drilling of 223
net wells resulting in P+P reserves of 769.4 bcf at a cost of $9.12
per boe.
- Sproule assigned 634.2 bcf of P+P reserves to the Upper Montney
related to the drilling of 170 net locations at a net cost of $0.94
billion or $8.90 per boe. In the Lower Montney, Sproule assigned P+P
reserves of 135.2 bcf related to 53 net locations at a net cost of
$0.23 billion or $10.15/boe. The net cost of a Lower Montney well of
$4.3 million per well is approximately $1.2 million lower than the
cost of an Upper Montney well as a significant portion of these wells
qualify for the Alberta Deep Royalty Incentive.
- In the Upper Montney, Sproule assigned average reserves of 3.7 bcf
per well and an initial average rate of 3.5 mmcf/d per well. To date
Advantage has drilled and tested 28 wells in the Upper Montney with
an average test rate of 5.1 mmcf/d per well.
- In the Lower Montney, Sproule assigned average reserves of 2.6 bcf
per well and an initial average rate of 2.5 mmcf/d per well. To date
Advantage has drilled and tested 7 wells in the Lower Montney with an
average test rate of 2.2 mmcf/d per well with the two most recent
Advantage wells in January and March 2010 testing at 4.6 mmcfd at 917
psi and 4.2 mmcfd at 495 psi.
- Over the entire Glacier land block, Sproule's total P+P (developed
and undeveloped) reserves were assigned at an average of 2.5
horizontal wells per section in the Upper Montney and 0.8 horizontal
wells per section in the Lower Montney.
Production Capability Currently Exceeds 90 mmcfd net
- Since December 2009, four new Upper Montney horizontals have
effectively pushed our existing facility capacity to the maximum
inlet design rate of 25 mmcfd and have caused us to shut-in several
Montney wells due to facility constraints. Combined with our joint
interest wells, production has reached peak rates of approximately 30
mmcfd.
- Construction of our new 50 mmcfd gas plant (100% Advantage W.I.),
expanded gas gathering system, and tie-in to the TCPL mainline is
nearing completion and commissioning of these facilities and new
wells will accommodate increased production during the second quarter
of 2010. Advantage's new gas plant is anticipated to reduce Glacier's
total operating costs from $8.25/boe to approximately $2.75/boe due
to the elimination of third party processing fees.
- Our current production capability including new wells tested to date
in both the Upper and Lower Montney zones exceeds 90 mmcfd. An
additional 5 gross (5 net) wells have been drilled and are waiting on
completion and testing.
- Advantage has also signed an agreement with TCPL to initiate work on
expanding the sales pipeline lateral to 100 mmcfd.
Nikanassin Drilling Update
- Advantage has completed the drilling of our first Nikanassin
horizontal well at Glacier with completion and testing of the well
expected to occur in the first half of 2010. We anticipate several
horizontal wells will be required to delineate the potential of the
Nikanassin which will require optimization of horizontal drilling and
completion techniques. We are encouraged with the future upside
potential of this resource play due to the combination of existing
Nikanassin production from several of our vertical wells on our land
block and geological mapping that indicates the targeted pay interval
reaches thicknesses of up to 50 meters.
- During the first quarter of 2010, we increased our Nikanassin land
position by a 2.7 gross (2.7 net) sections from a swap transaction
completed with a major producer. The additional sections increase
Advantage's Nikanassin land holdings to 73 gross (68 net) sections of
which the majority of Nikanassin rights lie directly within the
Glacier Montney land block.
Advantage is Well Positioned for Future Organic Growth
- The 2009 year-end Sproule proven and probable reserves forecast
includes total future development capital of $1.57 billion of which
$1.34 billion is allocated to Glacier. The development at Glacier
includes increasing production to 150 mmcfd over three years
including required facilities and infrastructure costs. The Sproule
Report forecasts the following operating cash flow and capital
expenditures for the next three years:
Operating Total Excess
Cash Flow(1) Capital Cash AECO
Year ($million) ($million) ($million) Cdn$/mcf
2010 $284 $221 $63 5.35
2011 $392 $348 $44 6.19
2012 $495 $364 $131 6.40
3 year total $1,171 $933 $238
(1) Includes Alberta Drilling Incentives, prior to G&A and interest
- The projected operating cash flows in the Sproule Report exceed the
required capital expenditures in each of the three years based on
Sproule's December 2009 commodity price forecasts. Sproule's price
forecasts are exclusive of any commodity price hedge positions.
Advantage has hedged 55% of our net natural gas production at $7.46
Cdn AECO per/mcf for 2010 which will enhance our ability to finance
the expenditures included in the Sproule Report.
- The reserve potential at Glacier which is measured in "TCF's" of
natural gas is economic at less than $5 Cdn per mcf. Advantage
intends to utilize a disciplined financial approach to development in
and effort to yield significant long term value growth for
shareholders. Advantage estimates that fully developing the Montney
resource potential at Glacier will require additional capital
expenditures in excess of $2.5 billion over the life of the project
which, if properly deployed, could result in significant reserve and
production growth.
Reserves
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 included herein are stated on a Company Interest basis (before royalty burdens and including royalty interests receivable) unless noted otherwise. This report 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.
Highlights - Company Interest Reserves (Working Interests plus Royalty
Interests Receivable)
December December
31, 2009 31, 2008
-------------------------------------------------------------------------
Proved plus probable reserves (mboe) 233,292 174,767
Present Value of reserves discounted at 10%,
before tax P+P ($000)(1) $2,773,428 $2,663,437
Net Asset Value per Unit discounted at 10%,
before tax $15.07 $14.03
Reserve Life Index (proved plus probable
- years)(2) 28.2 15.2
Reserves per Share/Unit (proved plus probable)(3) 1.43 1.22
Bank debt per boe of reserves(4) $1.06 $3.36
Convertible debentures per boe of reserves(4) $0.94 $1.25
(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 Q4 average production and company interest reserves.
(3) Based on 162.746 million Shares outstanding at December 31, 2009, and
142.825 million Units outstanding as December 31, 2008.
(4) 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.
Company Interest Reserves (Working Interests plus Royalty Interests
Receivable)
Summary as at December 31, 2009
Natural
Light & Heavy Gas Natural Oil
Medium Oil Oil Liquids Gas Equivalent
(mbbl) (mbbl) (mbbl) (mmcf) (mboe)
-------------------------------------------------------------------------
Proved
Developed
Producing 12,424 2,162 4,655 196,359 51,968
Developed
Non-producing 871 163 46 15,258 3,623
Undeveloped 2,622 191 606 297,603 53,019
Total Proved 15,917 2,516 5,307 509,220 108,611
-------------------------------------------------------------------------
Probable 13,637 3,394 2,495 630,930 124,681
Total Proved
+ Probable 29,554 5,910 7,802 1,140,150 233,292
-------------------------------------------------------------------------
Gross Working Interest Reserves (Working Interest only)
Summary as at December 31, 2009
Natural
Light & Heavy Gas Natural Oil
Medium Oil Oil Liquids Gas Equivalent
(mbbl) (mbbl) (mbbl) (mmcf) (mboe)
-------------------------------------------------------------------------
Proved
Developed
Producing 12,120 2,121 4,614 194,485 51,269
Developed
Non-producing 867 160 46 15,123 3,593
Undeveloped 2,615 185 606 297,598 53,005
Total Proved 15,602 2,466 5,266 507,206 107,868
-------------------------------------------------------------------------
Probable 13,524 3,370 2,483 630,116 124,396
Total Proved
+ Probable 29,126 5,836 7,749 1,137,322 232,264
-------------------------------------------------------------------------
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 $1,733,335 $ 950,359 $ 792,595
Developed Non-producing 107,413 64,138 53,072
Undeveloped 1,217,821 329,653 172,860
Total Proved 3,058,569 1,344,150 1,018,527
-------------------------------------------------------------------------
Probable 4,676,528 1,429,277 945,718
Total Proved + Probable $7,735,097 $2,773,428 $1,964,245
-------------------------------------------------------------------------
(1) Advantage's crude oil, natural gas and natural gas liquid reserves
were evaluated using Sproule's product price forecast effective
December 31, 2009 prior to the provision for income taxes, interests,
debt services charges and general and administrative expenses. It
should not be assumed that the discounted future revenue estimated by
Sproule represents the fair market value of the reserves.
(2) Assumes that development of each property will occur, without regard
to the likely availability to the Company of funding required for
that development.
Sproule Price Forecasts
The present value of future net revenue at December 31, 2009 was based upon crude oil and natural gas pricing assumptions prepared by Sproule effective December 31, 2009. These forecasts are adjusted for reserve quality, transportation charges and the provision of any applicable sales contracts. The price assumptions used over the next seven years are summarized in the table below:
Edmonton Alberta
WTI Light AECO-C Henry Hub Exchange
Crude Oil Crude Oil Natural Gas Natural Gas Rate
Year ($US/bbl) ($Cdn/bbl) ($Cdn/mmbtu) ($US/mmbtu) ($US/$Cdn)
-------------------------------------------------------------------------
2010 79.17 84.25 5.36 5.70 0.92
2011 84.46 89.99 6.21 6.48 0.92
2012 86.89 92.61 6.44 6.70 0.92
2013 90.20 96.19 7.23 7.43 0.92
2014 92.01 98.13 7.98 8.12 0.92
2015 93.85 100.11 8.16 8.28 0.92
2016 95.72 102.13 8.34 8.45 0.92
The Sproule price forecast does not include the impact of Advantage's commodity price hedging program. We currently have 55% of our net natural gas production hedged at an average price of $7.46 Cdn/mcf for 2010 and 27% hedged for 2011 at an average price of $6.30 Cdn/mcf. Crude oil hedges include 33% of our net crude oil production hedged at an average floor price of $67.83 Cdn/bbl for 2010.
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.
($000, except per
Unit/Share amounts) 0% 10% 15%
-------------------------------------------------------------------------
Net asset value per Unit(1)
- December 31, 2008 $ 40.23 $ 14.03 $ 9.16
-------------------------------------------------------------------------
Present value proved and probable
reserves $7,735,097 $2,773,428 $1,964,245
Undeveloped acreage and seismic(2) 177,124 177,124 177,124
Working capital (deficit) and
other (32,336) (32,336) (32,336)
Convertible debentures (218,471) (218,471) (218,471)
Bank debt (247,784) (247,784) (247,784)
Net asset value
- December 31, 2009 $7,413,630 $2,451,961 $1,642,778
-------------------------------------------------------------------------
Net asset value per Share(1)
- December 31, 2009 $ 45.55 $ 15.07 $ 10.09
-------------------------------------------------------------------------
(1) Based on 162.746 million Shares outstanding at December 31, 2009, and
142.825 million Units outstanding at December 31, 2008.
(2) Internal estimate
Gross Working Interest Reserves Reconciliation
Natural
Light & Heavy Gas Natural Oil
Medium Oil Oil Liquids Gas Equivalent
Proved (mbbl) (mbbl) (mbbl) (mmcf) (mboe)
-------------------------------------------------------------------------
Opening balance
Dec. 31, 2008 23,544 2,845 6,795 409,087 101,366
Extensions 200 15 32 98,159 16,607
Improved
recovery 0 0 0 0 0
Infill Drilling 50 29 0 107,947 18,070
Discoveries 0 0 0 0 0
Economic
factors 87 33 (59) (7,979) (1,269)
Technical
revisions (2,025) (63) 328 18,392 1,305
Acquisitions 0 0 0 0 0
Dispositions (3,991) (19) (997) (80,248) (18,382)
Production (2,263) (374) (833) (38,152) (9,829)
-------------------------------------------------------------------------
Closing
balance at
Dec. 31, 2009 15,602 2,466 5,266 507,206 107,868
-------------------------------------------------------------------------
Natural
Light & Heavy Gas Natural Oil
Proved + Medium Oil Oil Liquids Gas Equivalent
Probable (mbbl) (mbbl) (mbbl) (mmcf) (mboe)
-------------------------------------------------------------------------
Opening balance
Dec. 31, 2008 39,473 6,542 10,765 699,824 173,418
Extensions 231 23 33 432,402 72,354
Improved
recovery 0 0 0 0 0
Infill Drilling 74 45 0 166,927 27,940
Discoveries 0 0 0 0 0
Economic
factors 124 44 (57) (8,540) (1,312)
Technical
revisions (2,851) (415) (1,672) 5,018 (3102)
Acquisitions 0 0 0 0 0
Dispositions (5,663) (29) (1,487) (120,157) (27,205)
Production (2,263) (374) (833) (38,152) (9,829)
-------------------------------------------------------------------------
Closing
balance at
Dec. 31, 2009 29,125 5,836 7,749 1,137,322 232,264
-------------------------------------------------------------------------
Finding, Development & Acquisitions Costs ("FD&A")(1)(2)(3)
FD&A Costs - Gross Working Interest Reserves excluding Future Development
Capital
Proved +
Proved Probable
-------------------------------------------------------------------------
Capital expenditures ($000) $ 170,868 $ 170,868
Acquisitions net of dispositions ($000) (245,150) (245,150)
-------------------------------------------------------------------------
Total capital ($000) $ (74,282) $ (74,282)
-------------------------------------------------------------------------
Total mboe, end of period 107,868 232,264
Total mboe, beginning of period 101,366 173,418
Production, mboe 9,829 9,829
-------------------------------------------------------------------------
Reserve additions, mboe 16,331 68,675
-------------------------------------------------------------------------
FD&A costs ($/boe) $ (4.55) $ (1.08)
Three year average FD&A Costs ($/boe) $ 13.09 $ 5.66
F&D costs ($/boe) $ 10.46 $ 2.49
Three year average F&D costs ($/boe) $ 4.16 $ 9.91
NI 51-101
FD&A Costs - Gross Working Interest Reserves including Future Development
Capital
Proved +
Proved Probable
-------------------------------------------------------------------------
Capital expenditures ($000) $ 170,868 $ 170,868
Alberta Deep Royalty Incentives (26,900) (117,400)
Alberta Drilling Incentives (16,537) (21,887)
Acquisitions net of dispositions ($000) (245,150) (245,150)
Net change in Future Development Capital ($000) 485,109 909,633
-------------------------------------------------------------------------
Total capital ($000) $ 367,390 $ 696,064
-------------------------------------------------------------------------
Reserve additions, mboe 16,331 68,675
-------------------------------------------------------------------------
FD&A costs ($/boe) $ 22.50 $ 10.14
Three year average FD&A Costs ($/boe) $ 23.27 $ 13.34
F&D costs ($/boe) $ 10.58 $ 9.82
Three year average F&D costs ($/boe) $ 21.13 $ 12.21
(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.
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 in the press release relating to, among other things, resource estimates, timing of drilling, completion and testing of certain wells, expected results of the use of horizontal well and multi-frac technology, expected economics of development with respect to the Nikanassin formation, expected production and operating costs with respect to our Glacier Phase II Development Program and guidance and hedging. 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 and resources; 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 Advantage Energy Income Fund's (as predecessor to Advantage) Annual Information Form dated March 18, 2009 which is available on SEDAR at www.sedar.com.
References in this press release to test production rates, initial productivity, initial production capability, initial flow rates and average flowing pressure 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. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the 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. Such conversion rate is based on an energy equivalency conversion method application at the burner tip and does not represent an economic value equivalency at the wellhead.
%CIK: 0001468079
For further information: Investor Relations, Toll free: 1-866-393-0393, ADVANTAGE OIL & GAS LTD., 700, 400 - 3rd Avenue SW, Calgary, Alberta, T2P 4H2, Phone: (403) 718-8000, Fax: (403) 718-8300, Web Site: www.advantageog.com, E-mail: mailto:[email protected]
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