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Share Name | Share Symbol | Market | Type |
---|---|---|---|
Advantage Energy Ltd | TSX:AAV | Toronto | Common Stock |
Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
---|---|---|---|---|---|---|---|---|---|---|
-0.22 | -2.11% | 10.22 | 10.21 | 10.29 | 10.48 | 9.98 | 10.41 | 1,058,729 | 21:12:24 |
(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.
Highly Efficient Glacier 2P Reserves Additions at F&D Cost of $7.41/boe
Phase IV Drilling Program Update
Upper Montney Drilling Reaffirms High Productivity & Repeatability
Middle Montney Well Tests Reveals Liquids Potential
Lower Montney
Updated Glacier Montney Resource Assessment Increases TPIIP to 10 Tcf
Sproule Resource Assessment Results
(All reserve and resource volumes indicated are 'sales' except where otherwise indicated)
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 : |
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. |
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.
Copyright 2012 PR Newswire
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