Perpetual Energy Inc. Releases 2011 Year-End Reserves, 2011 Elmworth Contingent Resource and 2011 Bitumen Contingent Resource
CALGARY, Feb. 8, 2012 /CNW/ - (TSX:PMT) - Perpetual Energy Inc. ("Perpetual", the "Corporation" or the "Company") is pleased to release a summary of the Company's year-end 2011 reserves and Elmworth and Bitumen contingent resource information, as evaluated by the independent engineering firm McDaniel and Associates Consultants Ltd. ("McDaniel").
YEAR END 2011 RESERVES
2011 Year-End Reserve Highlights
- Perpetual added 48.1 Bcfe of proved and probable reserves in 2011, excluding production and net dispositions. The majority of the reserve additions were related to activities driven by Perpetual's asset base transformation and diversification strategy, adding natural gas and liquids reserves in the Alberta deep basin and in eastern Alberta adding Mannville heavy oil reserves. At year end 2011, oil and NGL represent 10 percent of Perpetual's total proved and probable reserves (12 percent of proved), up from 6 percent (8 percent of proved) at year-end 2010.
- After net dispositions of 12.2 Bcfe and production of 51.1 Bcfe in 2011, proved and probable reserves decreased less than 1% from 487.7 Bcfe at year-end 2010 to 484.7 Bcfe and proved reserves decreased six percent to 235.0 Bcfe at year-end 2011.
- Before downward revisions related solely to changes in natural gas pricing at year-end 2011 of 28.4 Bcfe, Perpetual's reserves grew five percent year over year from 487.7 Bcfe to 513.1 Bcfe.
- Reserve additions offsetting production and net dispositions were a result of total net capital spending of $105.2 million, including investment of $136.5 million in exploration and development capital spending programs, excluding spending for the development of additional working gas capacity at Perpetual's gas storage asset at Warwick ("Warwick Gas Storage").
- Including changes in future development capital ("FDC"), Perpetual realized finding and development costs ("F&D") of $2.89 per Mcfe ($17.34 per BOE) on a proved and probable reserve basis in 2011.
- Perpetual's realized finding, development and acquisition costs ("FD&A"), including changes in FDC, was $2.92 per Mcfe ($17.52 per BOE) on a proved and probable basis. Excluding the 28.4 Bcf of downward reserve revisions related to natural gas price reductions, FD&A including changes in FDC was $1.84 per Mcfe on a proved and probable basis.
- Perpetual's reserve to production ratio ("reserve life index" or "RLI") increased to 9.7 years from 8.4 years on a proved and probable reserves basis (increased to 5.3 years from 4.9 years on a proved reserves basis) at year-end 2011.
- Perpetual's reserve-based net asset value ("NAV") at year-end 2011 was estimated at $3.15 per Share discounted at eight percent.
Reserves Disclosure
Company interest reserves included herein are before royalty burdens and including royalty interests. Reserves information is based on an independent reserves evaluation report prepared by McDaniel dated February 6, 2012 with an effective date of December 31, 2011 (the "McDaniel Report"), and has been prepared in accordance with National Instrument 51-101 ("NI 51-101") using McDaniel's forecast prices and costs. Complete NI 51-101 reserves disclosure including after-tax reserve values, reserves by major property and abandonment costs will be included in Perpetual's Annual Information Form ("AIF"), which will be filed in March 2012.
Approximately 90 percent of Perpetual's proved and probable reserves are natural gas and as such the Corporation reports reserves in Mcf equivalent (Mcfe). Mcfe may be misleading, particularly if used in isolation. In accordance with NI 51-101 a Mcfe conversion ratio for oil of 1 Bbl: 6 Mcf has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not necessarily represent a value equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil 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.
Perpetual's reserves at year-end 2011 are summarized below.
| Reserves at December 31, 2011 | |||||
| Company Interest (Working plus Royalty Interest) |
Light and Medium Crude Oil (Mbbl) |
Heavy Oil (Mbbl) |
Natural Gas (MMcf) |
Natural Gas Liquids (Mbbl) |
Natural Gas Equivalent (MMcfe) |
| Proved Producing | 427 | 903 | 161,229 | 1,596 | 178,787 |
| Proved Non-Producing | - | 89 | 17,625 | 158 | 19,108 |
| Proved Undeveloped | 19 | 354 | 28,467 | 1,076 | 37,155 |
| Total Proved | 446 | 1,346 | 207,321 | 2,829 | 235,050 |
| Probable Producing | 191 | 460 | 59,457 | 633 | 67,164 |
| Probable Non-Producing excluding Gas Over Bitumen |
- | 158 |
24,433 | 100 |
25,978 |
| Probable Undeveloped | 93 | 480 | 116,835 | 1,320 | 128,194 |
| Probable Shut-in Gas over Bitumen | - | - | 28,319 | - | 28,319 |
| Total Probable | 284 | 1,098 | 229,044 | 2,053 | 249,656 |
| Total Proved and Probable | 730 | 2,444 | 436,365 | 4,882 | 484,705 |
The proved producing reserves comprise 76 percent of the total proved reserves and 37 percent of the total proved and probable reserves, while proved and probable producing reserves are 51 percent of the total proved and probable reserves. Total proved reserves account for 48 percent of the total proved and probable reserves. McDaniel estimates the FDC required to convert proved and probable non-producing and undeveloped reserves to proved producing reserves at $317.6 million. The table below summarizes the future development capital estimated by McDaniel by play type to bring undeveloped reserves to production.
| 5 Year Future Development Capital Schedule ($Millions) | |||||||
| Play | 2012 | 2013 | 2014 | 2015 | 2016 | 2017+ | Total |
| Conventional Shallow Gas | 4.2 | 1.1 | 1.0 | 0.7 | 0.5 | 1.8 | 9.3 |
| Eastern Alberta Viking | 0.8 | 5.1 | 18.1 | 25.5 | 20.2 | 97.4 | 167.0 |
| Mannville Heavy Oil | 13.3 | - | - | - | - | - | 13.3 |
| Greater Edson Wilrich | 15.4 | 25.0 | - | - | - | - | 40.4 |
| Carrot Creek Cardium | 2.9 | - | - | - | - | - | 2.9 |
| Other Deep Basin | 8.1 | 11.2 | - | - | - | 0.1 | 19.4 |
| Elmworth Montney | - | 49.5 | 3.9 | 12.0 | - | - | 65.4 |
| Total | 44.6 | 91.9 | 23.0 | 38.2 | 20.7 | 99.3 | 317.6 |
Reserves Reconciliation
| Company Interest (Working Interest + Royalty Interest) | |||||
| Natural Gas Equivalent (MMcfe) | Proved | Probable | Proved and Probable |
||
| Opening Balance December 31, 2010 | 250,402 | 237,329 | 487,731 | ||
| Discoveries and Extensions | 43,247 | 34,966 | 78,213 | ||
| Technical Revisions | 20,802 | (10,323) | 10,479 | ||
| Acquisitions, net of Dispositions | (8,387) | (3,829) | (12,216) | ||
| Production | (51,109) | 0 | (51,109) | ||
| Economic Factors | (19,905) | (8,487) | (28,392) | ||
| Closing Balance December 31, 2011 | 235,050 | 249,656 | 484,706 | ||
Year over year, McDaniel recorded net positive technical revisions totaling 10.5 Bcfe on a proved and probable basis. These positive revisions were due to improved performance and improved operating costs in a number of areas. These positive revisions were offset by a substantially reduced natural gas price forecast at year-end 2011 relative to year-end 2010, resulting in negative revisions of 28.4 Bcfe due to economic limits which primarily affected the forecast for wells as they near their end of productive life. Included in the downward price revisions are those future projects whose return on investment is negative at the current price forecast.
McDaniel's price forecast utilized in the evaluation is summarized below.
| McDaniel January 1, 2012 Price Forecast | |||||
| Year | West Texas Intermediate Crude Oil ($US/Bbl) |
Edmonton Light Crude Oil ($Cdn/Bbl) |
Natural Gas at AECO ($Cdn/MMBtu) |
Foreign Exchange ($US/$Cdn) |
|
| 2012 | 97.50 | 99.00 | 3.50 | 0.975 | |
| 2013 | 97.50 | 99.00 | 4.20 | 0.975 | |
| 2014 | 100.00 | 101.50 | 4.70 | 0.975 | |
| 2015 | 100.80 | 102.30 | 5.10 | 0.975 | |
| 2016 | 101.70 | 103.20 | 5.55 | 0.975 | |
| 2017 | 102.70 | 104.20 | 5.90 | 0.975 | |
| 2018 | 103.60 | 105.10 | 6.25 | 0.975 | |
| 2019 | 104.50 | 106.00 | 6.45 | 0.975 | |
| 2020 | 105.40 | 106.90 | 6.70 | 0.975 | |
| 2021 | 107.60 | 109.20 | 6.85 | 0.975 | |
| 2022 | 109.70 | 111.30 | 6.95 | 0.975 | |
| 2023 | 111.90 | 113.50 | 7.05 | 0.975 | |
| 2024 | 114.10 | 115.80 | 7.20 | 0.975 | |
| 2025 | 116.40 | 118.10 | 7.40 | 0.975 | |
| Escalation Post 2025 | 2% | 2% | 2% | 0.975 | |
RESERVE LIFE INDEX ("RLI")
Perpetual's proved and probable reserves to production ratio, also referred to as reserve life index, was 9.7 years at year-end 2011 while the proved RLI was 5.3 years, based upon the 2012 production estimates in the McDaniel Report. The following table summarizes Perpetual's historical calculated RLI.
| Reserve Life Index(1) | |||||
| 2011 | 2010 | 2009 | 2008 | 2007 | |
| Total Proved | 5.3 | 4.9 | 4.8 | 4.5 | 4.7 |
| Proved and Probable | 9.7 | 8.7 | 8.8 | 7.5 | 7.6 |
(1) Calculated as year-end reserves divided by year one production estimate from the McDaniel Report.
NET PRESENT VALUE ("NPV") OF RESERVES SUMMARY
Perpetual's light and medium oil, natural gas and natural gas liquids reserves were evaluated by McDaniel using McDaniel's product price forecasts effective January 1, 2012 prior to provision for financial natural gas price hedges, income taxes, interest, debt service charges and general and administrative expenses. The following table summarizes the NPV of funds flows from recognized reserves at January 1, 2012, assuming various discount rates. It should not be assumed that the discounted future net funds flows estimated by McDaniel represent the fair market value of the potential future production revenue of the company.
| NPV of Funds Flow Using McDaniel January 1, 2012 Forecast Prices and Costs | |||||
| Discounted at | |||||
| ($ thousands) | Undiscounted | 5% | 10% | 15% | |
| Proved Producing | $547,294 | $447,786 | $382,871 | $336,806 | |
| Proved Non-Producing | 79,637 | 37,780 | 23,962 | 18,358 | |
| Proved Undeveloped | 77,158 | 42,399 | 24,769 | 14,361 | |
| Total Proved | 704,089 | 527,964 | 431,603 | 369,525 | |
| Probable Producing | 237,827 | 155,002 | 113,418 | 88,826 | |
| Probable Non-Producing excl GOB | 68,571 | 48,351 | 37,842 | 30,971 | |
| Probable Undeveloped | 241,098 | 137,857 | 89,335 | 61,298 | |
| Probable Shut-in Gas over Bitumen | 92,135 | 66,913 | 50,162 | 38,606 | |
| Total Probable | 639,631 | 408,124 | 290,757 | 219,701 | |
| Total Proved and Probable | $1,343,720 | $936,089 | $722,360 | $589,226 | |
At a 10 percent discount factor, the proved producing reserves comprise 53 percent of the total proved and probable value, while proved and probable producing reserves represent 69 percent of the total proved and probable value. Total proved reserves account for 60 percent of the proved and probable value.
ELMWORTH CONTINGENT RESOURCE
A preliminary resource assessment was conducted in 2010 for the Montney Formation in the Elmworth area. These numbers have been mechanically updated to reflect increased reserve bookings by McDaniel as at year-end 2011, the results of which are summarized below.
| December 31, 2011 Elmworth Contingent Resource(1,3,4) | ||||||||||||
| Gross Lease | Working Interest | |||||||||||
| Original Gas in Place (MMcf) |
Raw Recoverable Gas (3) (MMcf) |
Sales Recoverable Gas (MMcf) |
Recoverable Natural Gas Liquids (Mbbl) |
Recoverable Natural Gas Equivalent (MMcfe) |
Recoverable Natural Gas Equivalent (MMcfe) |
|||||||
| Low(2) | 757,590 | 151,550 | 128,770 | 4,546 | 156,046 | 73,600 | ||||||
| Best(2) | 757,590 | 265,180 | 225,400 | 10,606 | 289,036 | 136,100 | ||||||
| High(2) | 757,590 | 378,790 | 321,970 | 18,939 | 435,604 | 204,800 | ||||||
| (1) | Contingent resources have been evaluated by McDaniel using the definitions is as defined in section five of the Canadian Oil and Gas Evaluators Handbook, Volume 1. All volumes are reported before the deduction of royalties payable to others. Contingent resource assignments are in addition to any reserve assignments associated with these assets. This is a mechanical update to the December 31st, 2010 Resource assessment to account for 41.5 BCFe of Proved and Probable reserves that have been booked to this asset. |
| (2) | A Low estimate (90% chance the ultimate recoverable resource will be equal or greater than the stated value), means higher certainty, a Best estimate (50% chance that the ultimate recoverable resource will be greater than or equal to the stated value) means most likely and a High estimate means lower than a 50% chance that the ultimate recoverable resource will be greater than or equal to the stated value. |
| (3) | McDaniel has assigned recovery factors of 20% (Low), 35% (Best) and 50% (High) in their assessment of recoverable resource. |
| (4) | Contingent resources can be sub-classified into economic and uneconomic portions based on a number of assumptions on capital costs, timing, price forecast, etc. Currently sub-classification of these estimates has not been completed pending a discussion of the above parameters. |
The primary contingencies identified for the Montney resource were infrastructure and access to market. To date, 41.5 BCFe of reserves have been booked as proved and probable subject to standard booking practice for undeveloped reserves. The total of the contingent resource plus the reserve booking to date matches the original best case net resource booking of 178 BCFe for this area.
BITUMEN CONTINGENT RESOURCE
Bluesky Contingent Resource in Panny Area
Perpetual holds over 41,400 hectares (162 net sections) of oil sands leases in the Panny Area of Northern Alberta. Throughout 2011, the company has worked with McDaniel to provide estimates of volumes of discovered bitumen initially in place ("DBIIP"), undiscovered bitumen initially in place ("UDBIIP"), contingent resources and prospective resources for a portion of the Company's assets in this area. Three vertical wells and a horizontal well were drilled in the area in the first quarter of 2011, and one existing well was deepened in the fourth quarter to evaluate the reservoir quality and bitumen characteristics of the Bluesky formation and to further define the extent of the bitumen resource and extraction potential. The assignments of DBIIP, UDBIIP, recoverable contingent resource and recoverable prospective resource in the McDaniel Report "Perpetual Energy Inc. Clastic Oil sands Resource Assessment Evaluation of Bitumen and Heavy Oil Resources as of June 30, 2011" and the subsequent update "Evaluation of Discovered Bitumen Initially-in-Place and Contingent Bitumen Resources - Panny Area" effective December 31, 2011 are based on approximately 59 wells in the pools, and on the potential application of cyclic steam stimulation to the Bluesky formation. These reports were prepared pursuant to National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities".
Given the extent of the bitumen resource now confirmed across the Panny acreage, the high quality of the Bluesky formation reservoir recovered in core, and that the viscosity of the bitumen discovered is capable of flowing at low rates without any thermal or solvent assistance, the Corporation is encouraged by the results to date at Panny. Perpetual has plans to further quantify the resource through additional drilling, has initiated a detailed review of applicable technologies, and has applied for a pilot test on its lands.
Hoole and Marten Hills Areas
Perpetual holds over 41,000 hectares (161 net sections) of oil sands leases in the Hoole and Marten Hills Areas of Northern Alberta. Throughout 2011, the company has worked with McDaniel to provide estimates of volumes of UDBIIP, DBIIP, contingent resources and prospective resources for a portion of the Company's assets in these areas. Three vertical wells were drilled in the area and 13 km of 2D seismic were acquired in the first quarter of 2011, to evaluate the reservoir quality and bitumen characteristics of the Clearwater and Grand Rapids formations and to further define the extent of the bitumen resource and extraction potential. The assignments of DBIIP, UDBIIP, recoverable contingent resource and recoverable prospective resource in the McDaniel Report "Perpetual Energy Inc. Clastic Oil sands Resource Assessment Evaluation of Bitumen and Heavy Oil Resources as of June 30, 2011" are based on 57 wells in the pools, and on the potential application of cyclic steam stimulation to the Clearwater formation and Steam Assisted Gravity Drainage ("SAGD") to the Grand Rapids formation. The Report was prepared pursuant to National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities".
Liege Area
Perpetual holds 30,720 hectares (120 net sections) of oil sands leases in the Liege area. During the first quarter of 2011, the Company acquired 42 km of 2D seismic and drilled three wells which encountered bitumen-saturated reservoir in the Wabiskaw as well as in the Grosmont A, B and C and Leduc carbonate formations. Each of the three wells encountered three or more stacked zones, with at least one zone having greater than 10 meters of continuous bitumen-saturated reservoir. The assignments of DBIIP, UDBIIP, recoverable contingent resource and recoverable prospective resource in the McDaniel Report "Perpetual Energy Inc. Evaluation of Contingent and Prospective Resources of Grosmont and Leduc Bitumen As of October 31, 2011" are based on 55 wells in the pools and on the potential application of SAGD. The Report was prepared pursuant to National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities".
Net Present Value of Resource
All of Perpetual's contingent resources currently have an "undetermined" economic status as sub-classification into economic and uneconomic categories has not been evaluated. Contingencies affecting the classification of the resources referred to in the McDaniel Reports referenced in the sections above as reserves include corporate development plans, the need for regulatory approval, and the need to perform an economic study regarding production. There is no certainty that it will be commercially viable to produce any portion of the resources. Please see "Notes Pertaining to the Reporting of Bitumen Contingent Resource" below for applicable definitions and risk factors.
The bitumen in place and recoverable resource estimates, prepared in accordance with the COGE Handbook, are as follows:
| Discovered(1) | Undiscovered(1) | |||||||
| |
Gross Area (hectares) |
Company WI |
DBIIP (Mbbl) |
Gross Recoverable Contingent Resource (Mbbl) (1) |
Gross Area (hectares) |
Company WI |
UDBIIP (Mbbl) |
Gross Recoverable Prospective Resource (Mbbl) (1) |
| Resource Category | ||||||||
| Panny Clastics | ||||||||
| Low Estimate(1) | 100% | 509,242 | 50,924 | |||||
| Best Estimate(1) | 5,184 | 100% | 755,009 | 132,127 | ||||
| High Estimate(1) | 100% | 983,040 | 245,760 | |||||
| Other Clastics | ||||||||
| Low Estimate(1) | 100% | 36,467 | 5,470 | 100% | 71,800 | 7,719 | ||
| Best Estimate(1) | 610 | 100% | 70,691 | 14,178 | 676 | 100% | 82,802 | 17,604 |
| High Estimate(1) | 100% | 128,406 | 33,589 | 100% | 167,274 | 46,737 | ||
| Liege Carbonates | ||||||||
| Low Estimate(1) | 100% | 270,416 | 0 | 100% | 1,629,912 | 0 | ||
| Best Estimate(1) | 2,717 | 100% | 331,190 | 66,238 | 18,002 | 100% | 1,996,227 | 399,245 |
| High Estimate(1) | 100% | 405,623 | 162,250 | 100% | 2,444,868 | 977,947 | ||
| Total All Areas | ||||||||
| Low Estimate(1) | 100% | 816,125 | 56,394 | 100% | 1,701,712 | 7,719 | ||
| Best Estimate(1) | 8,511 | 100% | 1,156,890 | 212,543 | 18,678 | 100% | 2,079,029 | 416,849 |
| High Estimate(1) | 100% | 1,517,069 | 441,599 | 100% | 2,612,143 | 1,024,684 | ||
| (1) | Contingent and prospective resources have been evaluated by McDaniel using the definitions is as defined in section five of the Canadian Oil and Gas Evaluators Handbook, Volume 1. All volumes are reported before the deduction of royalties payable to others. Contingent resource assignments are in addition to any reserve assignments associated with these assets. Please refer to the detailed definitions contained at the end of this release. |
NET ASSET VALUE ("NAV")
The following net asset value table shows what is normally referred to as a "produce-out" NAV calculation under which the Corporation'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. It should not be assumed that the NAV represents the fair market value of Perpetual Shares. The calculations below do not reflect the value of the Corporation's prospect inventory to the extent that the prospects are not recognized within the NI-51-101 compliant reserve assessment.
The value of the Corporation's Warwick Gas Storage asset has been recorded at cost in the net asset value calculation below. Construction of the Warwick Gas Storage facility was completed in the fourth quarter of 2010.
| Pre-tax Net Asset Value at December 31, 2011(1) | ||||
| ($millions except as noted) | Undiscounted | 5% | 8% | Discounted at 10% |
| Total Proved and Probable Reserves(2) | $1,344 | $936 | $795 | $722 |
| Fair Market Value of Undeveloped Land(3) | $188 | $188 | $188 | $188 |
| Market Value of TriOil Resources Ltd. Shares | $4 | $4 | $4 | $4 |
| Warwick Gas Storage(4) | $85 | $85 | $85 | $85 |
| Net Bank Debt (unaudited)(5) | ($142) | ($142) | ($142) | ($142) |
| Convertible Debentures (unaudited) | ($235) | ($235) | ($235) | ($235) |
| Senior Notes | ($150) | ($150) | ($150) | ($150) |
| Estimate of Additional Future Abandonment and Reclamation Costs(6) | ($121) | ($69) | ($52) | ($43) |
| Mark to McDaniel's cost of WGSI Forward Sale Obligation (7) | ($42) | ($35) | ($31) | ($29) |
| Net Asset Value | $932 | $583 | $463 | $401 |
| Shares Outstanding (million) - basic | 147 | 147 | 147 | 147 |
| Net Asset Value per Share ($/Share) | $6.34 | $3.97 | $3.15 | $2.73 |
| (1) | Financial information is per Perpetual's 2011 preliminary unaudited consolidated financial statements. |
| (2) | Reserve values per McDaniel Report as at December 31, 2011. |
| (3) | Independent Third party estimate. |
| (4) | Book value recorded at cost as at December 31, 2011. |
| (5) | Includes bank debt, net of working capital excluding marketable securities. |
| (6) | Amounts are net of salvage value and in addition to amounts in the McDaniel report for future well abandonment costs related to developed reserves. See "ABANDONMENT AND RECLAMATION COSTS". |
| (7) | Value of Perpetual's open hedging transactions related to the Warwick Gas Storage funding arrangement at year end 2011 assuming settlement against the McDaniel price forecast. |
In the absence of adding reserves to the Corporation, the NAV per share will decline as the reserves are produced out. The above evaluation includes future capital expenditure expectations required to bring undeveloped reserves recognized by McDaniel that meet the criteria for booking under NI 51-101 on production.
FAIR MARKET VALUE OF UNDEVELOPED LAND
Perpetual's independent third party estimate of the fair market value of its undeveloped acreage by region for purposes of the above net asset value calculation is based on recent Crown land sale activity adjusted for tenure and other considerations and is as follows:
| Fair Market Value of Undeveloped Land | |||
| Area | Acres | Total Value ($) | $/Acre |
| North | 903,786 | $34,663,049 | $38.35 |
| South | 446,867 | 44,711,295 | 100.06 |
| West Central | 143,751 | 56,184,210 | 390.84 |
| New Ventures | 20,230 | 1,921,025 | 94.96 |
| Oil Sands | 334,379 | 50,769,809 | 151.83 |
| Totals | 1,849,013 | $188,249,388 | $101.81 |
ABANDONMENT AND RECLAMATION COSTS
In addition to the abandonment cost estimates provided by McDaniel inclusive in their reserve assessment, Perpetual compiles annually a detailed internal estimate of the Corporation's total future asset retirement obligation based on net ownership interest in all wells, facilities and pipelines, including estimated costs to abandon the wells, facilities and pipelines and reclaim the sites, and the estimated timing of the costs to be incurred in future periods. Pursuant to this evaluation, the estimated value of Perpetual's future asset retirement obligations, net of the estimated salvage value of facilities and equipment and discounted at eight percent is $76 million as at December 31, 2011. The McDaniel Report includes an undiscounted amount of $81 million with respect to expected future well abandonment costs related specifically to proved and probable reserves and such amount is included in the values captioned "Total Proved and Probable Reserves" in the NPV of Funds Flow table (see "NET PRESENT VALUE ("NPV") OF RESERVES SUMMARY"). Of the total future well abandonment costs included in the McDaniel Report an undiscounted amount of $55 million relates to Perpetual's developed reserves. The following table presents the estimated future asset retirement obligations and estimated net salvage values at various discount rates:
| Abandonment and Reclamation Costs | ||||
| ($millions, net to Perpetual) | Undiscounted | 5% | 8% | Discounted at 10% |
| Well abandonment costs for developed reserves included in McDaniel Report | $55 | $32 | $25 | $21 |
| Well abandonment costs for undeveloped reserves included in McDaniel Report | 26 | 14 | 10 | 8 |
| Well abandonment costs for Total Proved and Probable reserves included in McDaniel Report | 81 | 46 | 35 | 30 |
| Estimate of other abandonment and reclamation costs not included in McDaniel Report | 246 | 141 | 107 | 90 |
| Total estimated future abandonment and reclamation costs | 326 | 188 | 142 | 120 |
| Salvage value | (151) | (87) | (66) | (55) |
| Abandonment and reclamation costs , net of salvage | 175 | 101 | 76 | 64 |
| Well abandonment costs for developed reserves included in McDaniel Report | (55) | (32) | (25) | (21) |
| Estimate of additional future abandonment and reclamation costs, net of salvage(1) | $121 | $69 | $52 | $43 |
| (1) | Future abandonment and reclamation costs not included in the McDaniel Report, net of salvage value. |
FINDING, DEVELOPMENT AND ACQUISITION ("FD&A") COSTS
Under NI 51-101, the methodology to be used to calculate FD&A costs includes incorporating changes in future development capital required to bring the proved undeveloped and probable reserves to production. For continuity, Perpetual has presented herein FD&A costs calculated both excluding and including FDC. Changes in forecast FDC occur annually as a result of development activities, acquisitions and disposition activities and capital cost estimates that reflect the independent evaluator's best estimate of what it will cost to bring the proved undeveloped and probable reserves on production. The decrease in FDC is the result of projects being deemed to be uneconomic under the current McDaniel price forecast. Perpetual believes that the underlying resource is still present and those projects will be added back if natural gas prices increase in the future.
The following table summarizes Perpetual's F&D cost as well as finding, development and acquisition costs, before and after the inclusion of changes in FDC. Finding and development costs, including changes in FDC were $2.89 per Mcfe ($17.34 per BOE) on a proved and probable basis in 2011.
Perpetual has also summarized in the table below these same metrics with the effect of the price-related revisions removed. Perpetual believes that the majority of these reserves will return to the books with a recovery in natural gas prices as the technical merits for booking the reserves have not changed, only the economic circumstances. Excluding the effects of negative reserve revisions related to substantially lower forward gas prices, including changes in FDC, Perpetual's F&D costs were $1.96 per Mcfe ($11.76 per BOE) for proved and probable reserves and FD&A costs were $1.84 per Mcfe ($11.04 per BOE) in 2011 on a proved and probable basis.
| 2011 FD&A Costs - Company Interest Reserves | ||||
| ($millions (unaudited), except as noted) | Proved | Proved Excluding Price Revisions(2) |
Proved & Probable |
Proved and Probable Excluding Price Revisions(3) |
| F&D Costs, Excluding FDC | ||||
| Exploration and Development Capital Expenditures(1) | $138.6 | $138.6 | $138.6 | $138.6 |
| Reserve Additions Including Revisions - Bcfe | 44.1 | 64.1 | 60.3 | 88.7 |
| F&D - $/Mcfe(4) | $3.14 | $2.16 | $2.30 | $1.56 |
| F&D Costs, Including FDC | ||||
| Exploration and Development Capital Expenditures | $138.6 | $138.6 | $138.6 | $138.6 |
| Total Change in FDC | 40.4 | 40.4 | 35.4 | 35.4 |
| Total F&D Capital including Change in FDC | $179.0 | $179.0 | $174.0 | $174.0 |
| Reserve Additions Including Revisions - Bcfe | 44.1 | 64.1 | 60.3 | 88.7 |
| F&D Costs- $/Mcfe(4) | $4.06 | $2.80 | $2.89 | $1.96 |
| FD&A Costs, Excluding FDC | ||||
| Exploration and Development Capital Expenditures | $138.6 | $138.6 | $138.6 | $138.6 |
| Net Acquisitions | (33.40) | (33.40) | (33.40) | (33.40) |
| FD&A Capital Expenditures Including Net Acquisitions | $105.23 | $105.23 | $105.23 | $105.23 |
| Reserve Additions Including Net Acquisitions - Bcfe | 35.8 | 55.7 | 48.1 | 76.5 |
| FD&A Costs - $/Mcfe(4) | $2.94 | $1.89 | $2.19 | $1.38 |
| FD&A Costs, Including FDC | ||||
| FD&A Capital Expenditures Including Net Acquisitions | $105.23 | $105.23 | $105.23 | $105.23 |
| Total Change in FDC | 40.4 | 40.4 | 35.4 | 35.40 |
| Total FD&A Capital Including Change in FDC | $145.63 | $145.63 | $140.63 | $140.63 |
| Reserve Additions Including Net Acquisitions - Bcfe | 35.8 | 55.7 | 48.1 | 76.5 |
| FD&A Costs Including FDC - $/Mcfe(4) | $4.07 | $2.62 | $2.92 | $1.84 |
| (1) | $11.1 MM of capital associated with the Warwick Gas Storage project has been excluded, includes $16.5 million of undeveloped land capital. |
| (2) | 19.9 Bcf of proved reserves associated with price related revisions have been added back into the total reserve additions and revisions. |
| (3) | 28.4 Bcf of proved and probable reserves associated with price related revisions have been added back into the total reserve additions and revisions. |
| (4) | The aggregate of exploration and development costs incurred in the most recent financial year and the change in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year. |
| Company Interest Historic FD&A Costs ($/MCFE) | |||
| 2011 | 2010 | 2009 | |
| Proved Reserves | |||
| Annual FD&A, Excluding FDC | 2.94 | 2.69 | 4.48 |
| Three year average FD&A, Excluding FDC(1) | 3.26 | 3.34 | 3.08 |
| Annual FD&A, Including FDC | 4.07 | 2.68 | 4.07 |
| Three year average FD&A Including FDC(1) | 3.44 | 3.06 | 3.25 |
| Proved and Probable Reserves | |||
| Annual FD&A, Excluding FDC | 2.19 | 2.31 | 4.09 |
| Three year average FD&A, Excluding FDC(1) | 2.73 | 2.87 | 1.97 |
| Annual FD&A, Including FDC | 2.92 | 2.62 | 2.41 |
| Three year average FD&A, Including FDC(1) | 2.66 | 2.54 | 2.52 |
| (1) | Three year weighted average |
Additional Information
Perpetual will release its 2011 annual audited financial statements and management's discussion and analysis ("MD&A") on or about March 6, 2012.
Notes Pertaining to the Reporting of Bitumen Contingent Resource
The following are excerpts from the definitions of resources and reserves, contained in Section 5 of the COGE Handbook, which is referenced by the Canadian Securities Administrators in National Instrument 51-101, "Standards of Disclosure for Oil and Gas Activities".
Definitions
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. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters, or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingent Resources are further classified in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status. [Criteria for determining commerciality are further detailed in the COGE Handbook Section 5.3.4].
Discovered Petroleum Initially-In-Place (DPIIP) (equivalent to discovered resources) 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.
Economic Contingent Resources are those contingent resources which are currently economically recoverable.
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.
Undiscovered Petroleum Initially-In-Place (UDPIIP) (equivalent to undiscovered resources) is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations yet to be discovered. The recoverable portion of undiscovered petroleum initially in place is referred to as "prospective resources" the remainder as unrecoverable.
Total Petroleum Initially-In-Place (PIIP) 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 (equivalent to "total resources").
Uncertainty Categories for Resource Estimates
The range of uncertainty of estimated recoverable volumes may be represented by either deterministic scenarios or by a probability distribution. Resources should be provided as low, best, and high estimates 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.
This approach to describing uncertainty may be applied to reserves, contingent resources, and prospective resources. There may be significant risk that sub-commercial and undiscovered accumulations will not achieve commercial production. However, it is useful to consider and identify the range of potentially recoverable quantities independently of such risk.
Levels of Certainty for Reported Reserves
With respect to contingent resources, not all technically feasible development plans will be commercial. The commercial viability of a development project is dependent on the forecast of fiscal conditions over the life of the project. For contingent resources the risk component relating to the likelihood that an accumulation will be commercially developed is referred to as the "chance of development." For contingent resources the chance of commerciality is equal to the chance of development.
Risk Factors
In general, estimates of gross original resources and recoverable resources are based upon a number of factors and assumptions made as of the date on which the estimates were determined, such as geological, technological and engineering estimates and are subject to a variety of risks and uncertainties and other factors that could cause actual events or results to differ materially from those anticipated in forward-looking estimates.
These risks and uncertainties include but are not limited to: (1) the fact that there is no certainty that the zones of interest will exist to the extent estimated or that the zones will be found to have oil with characteristics that meet or exceed the minimum criteria in terms of net pay thickness, porosity or oil saturation, or that the oil will be commercially recoverable to the extent estimated; (2) risks inherent in the heavy oil and oil sands industry; (3) the lack of additional financing to fund the Corporation's exploration activities and continued operations; (4) fluctuations in foreign exchange and interest rates; (5) the number of competitors in the oil and gas industry with greater technical, financial and operations resources and staff; (6) fluctuations in world prices and markets for oil and gas due to domestic, international, political, social, economic and environmental factors beyond the Corporation's control; (7) changes in government regulations affecting oil and gas operations and the high compliance cost with respect to governmental regulations; (8) potential liabilities for pollution or hazards against which the Corporation cannot adequately insure or which the Corporation may elect not to insure; (9) the Corporation's ability to hire and retain qualified employees and consultants; (10) contingencies affecting the classification as reserves versus resources which relate to the following issues as detailed in the COGE Handbook: ownership considerations, drilling requirements, testing requirements, regulatory considerations, infrastructure and market considerations, timing of production and development, and economic requirements; (11) the fact that there is no certainty that any portion of contingent resources will be commercially viable to produce; (12) the fact that there is no certainty that any portion of the prospective resources will be discovered and if discovered, there is no certainty that it will be commercially viable to produce any portion of the resources; and (13) other factors beyond the Corporation's control. Any reference in this press release to DPIIP, UDPIIP, contingent resources and prospective resources are not, and should not be confused with oil and gas reserves.
Unaudited financial information
Certain financial and operating information included in this press release for the quarter and year ended December 31, 2011, such as FD&A costs and funds flow are based on estimated unaudited financial results for the quarter and year then ended, and are subject to the same limitations as discussed under "Forward-Looking Information". These estimated amounts may change upon the completion of audited financial statements for the year ended December 31, 2011 and changes could be material. See "Non-IFRS Measures".
Financial Outlooks
Included in this press release are estimates of Perpetual's 2012 funds flow outlook, which are based on the various assumptions as to production levels, capital expenditures, and other assumptions disclosed in this press release and including commodity price assumptions. To the extent such estimates constitute a financial outlook, they were approved by management of Perpetual on February 7, 2012 and are included to provide readers with an understanding of Perpetual's anticipated 2012 funds flow based on the capital expenditures and other assumptions described herein and readers are cautioned that the information may not be appropriate for other purposes.
Non-IFRS Measures
This news release includes references to financial measures commonly used in the oil and gas industry such as "funds flow" ", "reserve life index" and "net debt", which do not have any standardized meaning prescribed by International Financial Reporting Standards ("IFRS"). Management believes that in addition to net income, funds flow and net bank debt are useful supplemental measures as they are a measure of a company's ability to generate the cash necessary to repay debt or fund future growth through capital investment. However, investors are cautioned that these measures should not be construed as an alternative to net income determined in accordance with IFRS as an indication of Perpetual's performance. The method of calculating these measures may differ from other companies and, accordingly, they may not be comparable to similar measures used by other companies. For these purposes, "funds flow" is defined as cash provided by operations before changes in non-cash working capital gas over bitumen royalty adjustments not yet received, settlement of decommissioning obligations and certain exploration costs and "net bank debt is defined as long-term bank debt plus working capital (adjusted for the fair value of financial instruments and future taxes).
Forward-Looking Information
Certain information regarding Perpetual in this news release including management's assessment of future plans and operations may constitute forward-looking statements under applicable securities laws. The forward looking information includes, without limitation, anticipated amounts and allocation of capital spending; statements regarding estimated production and timing thereof; prospective drilling, forecast average production; completions and development activities; estimated recoverable contingent resources; plans to further quantify contingent resources; estimated FDC required to convert proved and probable non-producing and undeveloped reserves to proved producing reserves; anticipated effect of commodity prices on reserves; estimates of gross recoverable gas sales; estimated net asset value; prospective oil and natural gas liquids production capability; projected realized natural gas prices and funds flow; projected ending 2012 net debt; estimated asset retirement obligations; anticipated effect of commodity prices on future development capital and reserves; commodity prices and foreign exchange rates; and gas price management. Various assumptions were used in drawing the conclusions or making the forecasts and projections contained in the forward-looking information contained in this press release, which assumptions are based on management analysis of historical trends, experience, current conditions and expected future developments pertaining to Perpetual and the industry in which it operates as well as certain assumptions regarding the matters outlined above. Forward-looking information is based on current expectations, estimates and projections that involve a number of risks, which could cause actual results to vary and in some instances to differ materially from those anticipated by Perpetual and described in the forward-looking information contained in this press release. Undue reliance should not be placed on forward-looking information, which is not a guarantee of performance and is subject to a number of risks or uncertainties, including without limitation those described under "Risk Factors" in Perpetual's MD&A for the year ended December 31, 2010 and those included in reports on file with Canadian securities regulatory authorities which may be accessed through the SEDAR website (www.sedar.com and at Perpetual's website www.perpetualenergyinc.com). Readers are cautioned that the foregoing list of risk factors is not exhaustive. Forward-looking information is based on the estimates and opinions of Perpetual's management at the time the information is released and Perpetual disclaims any intent or obligation to update publicly any such forward-looking information, whether as a result of new information, future events or otherwise, other than as expressly required by applicable securities law.
Non-GAAP Measures
This news release contains financial measures that may not be calculated in accordance with generally accepted accounting principles in Canada ("GAAP"). Readers are referred to advisories and further discussion on non-GAAP measures contained in the "Significant Accounting Policies and Non-GAAP Measures" section of Perpetual's MD&A for the year ended December 31, 2010.
Perpetual Energy Inc. is a natural gas-focused Canadian energy company. Perpetual's shares and Convertible Debentures are listed on the Toronto Stock Exchange under the symbols "PMT", "PMT.DB.C", "PMT.DB.D" and "PMT.DB.E". Further information with respect to Perpetual can be found at its website at www.perpetualenergyinc.com.
The Toronto Stock Exchange has neither approved nor disapproved the information contained herein.
Perpetual Energy Inc.
Suite 3200, 605 - 5 Avenue SW Calgary, Alberta, Canada T2P 3H5
Telephone: 403 269-4400 Fax: 403 269-4444 Email: [email protected]
Susan L. Riddell Rose, President and Chief Executive Officer
Cameron R. Sebastian, Vice President, Finance and Chief Financial Officer
Claire A. Rosehill, Investor Relations and Business Analyst
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