Perpetual Energy Inc. Releases 2011 Year-End Reserves, 2011 Elmworth Contingent Resource and 2011 Bitumen Contingent Resource
CALGARY, Feb. 8, 2012 /PRNewswire/ – (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
Light and
Company Interest Medium Heavy Natural Natural Gas
(Working plus CrudeOil Oil Natural Gas Gas Liquids Equivalent
RoyaltyInterest) (Mbbl) (Mbbl) (MMcf) (Mbbl) (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
CompanyInterest(Working Interest +
Royalty Interest)
Proved
Natural Gas Equivalent (MMcfe) Proved Probable 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.
McDanielJanuary 1, 2012
PriceForecast
West Texas
Intermediate Edmonton Light Natural Gas at Foreign
Crude Oil Crude Oil AECO Exchange
Year ($US/Bbl) ($Cdn/Bbl) ($Cdn/MMBtu) ($US/$Cdn)
2012 97.50 99.00 3.50 0.975
2013 97.50 99.00 4.20 0.975
2014 100.00 101.50 4.70 0.975
2015 100.80 102.30 5.10 0.975
2016 101.70 103.20 5.55 0.975
2017 102.70 104.20 5.90 0.975
2018 103.60 105.10 6.25 0.975
2019 104.50 106.00 6.45 0.975
2020 105.40 106.90 6.70 0.975
2021 107.60 109.20 6.85 0.975
2022 109.70 111.30 6.95 0.975
2023 111.90 113.50 7.05 0.975
2024 114.10 115.80 7.20 0.975
2025 116.40 118.10 7.40 0.975
Escalation Post 2% 2% 2% 0.975
2025
RESERVE LIFE INDEX (“RLI”)
Perpetual’s proved and probable reserves to production ratio, also
referred to as reserve life index, was 9.7 years at year-end 2011 while
the proved RLI was 5.3 years, based upon the 2012 production estimates
in the McDaniel Report. The following table summarizes Perpetual’s
historical calculated RLI.
ReserveLife Index(1)
2011 2010 2009 2008 2007
Total Proved 5.3 4.9 4.8 4.5 4.7
Proved and Probable 9.7 8.7 8.8 7.5 7.6
((1) )Calculated as year-end reserves divided by year one production estimate
from the McDaniel Report.
NET PRESENT VALUE (“NPV”) OF RESERVES SUMMARY
Perpetual’s light and medium oil, natural gas and natural gas liquids
reserves were evaluated by McDaniel using McDaniel’s product price
forecasts effective January 1, 2012 prior to provision for financial
natural gas price hedges, income taxes, interest, debt service charges
and general and administrative expenses. The following table summarizes
the NPV of funds flows from recognized reserves at January 1, 2012,
assuming various discount rates. It should not be assumed that the discounted future net funds flows estimated by McDaniel represent the fair market value of the
potential future production revenue of the company.
NPV of Funds Flow Using McDaniel January 1, 2012 Forecast Prices
and Costs
Discounted at
($ 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 68,571 48,351 37,842 30,971
GOB
Probable Undeveloped 241,098 137,857 89,335 61,298
Probable Shut-in Gas over 92,135 66,913 50,162 38,606
Bitumen
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
Recoverable Recoverable Recoverable
Original Raw Sales Natural Natural Natural
Gas in Recoverable Recoverable Gas Gas Gas
Place Gas(3) Gas Liquids Equivalent Equivalent
(MMcf) (MMcf) (MMcf) (Mbbl) (MMcfe) (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 Gross
Recoverable Recoverable
Gross Contingent Gross Prospective
Area Company DBIIP Resource Area Company UDBIIP Resource
(hectares) WI (Mbbl) (Mbbl)(1) (hectares) WI (Mbbl) (Mbbl)(1)
Resource
Category
Panny
Clastics
Low 509,242 50,924
Estimate
(1) 100%
Best 5,184 755,009 132,127
Estimate
(1) 100%
High 983,040 245,760
Estimate
(1) 100%
Other
Clastics
Low 36,467 5,470 71,800 7,719
Estimate
(1) 100% 100%
Best 610 70,691 14,178 676 82,802 17,604
Estimate
(1) 100% 100%
High 128,406 33,589 167,274 46,737
Estimate
(1) 100% 100%
Liege
Carbonates
Low 270,416 0 1,629,912 0
Estimate
(1) 100% 100%
Best 2,717 331,190 66,238 18,002 1,996,227 399,245
Estimate
(1) 100% 100%
High 405,623 162,250 2,444,868 977,947
Estimate
(1) 100% 100%
Total All
Areas
Low 816,125 56,394 1,701,712 7,719
Estimate
(1) 100% 100%
Best 8,511 1,156,890 212,543 18,678 2,079,029 416,849
Estimate
(1) 100% 100%
High 1,517,069 441,599 2,612,143 1,024,684
Estimate
(1) 100% 100%
(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 Undiscounted 5% 8% Discounted at 10%
noted)
Total Proved and Probable $1,344 $936 $795 $722
Reserves(2)
Fair Market Value of $188 $188 $188 $188
Undeveloped Land(3)
Market Value of TriOil $4 $4 $4 $4
Resources Ltd. Shares
Warwick Gas Storage(4) $85 $85 $85 $85
Net Bank Debt (unaudited) ($142) ($142) ($142) ($142)
(5)
Convertible Debentures ($235) ($235) ($235) ($235)
(unaudited)
Senior Notes ($150) ($150) ($150) ($150)
Estimate of Additional ($121) ($69) ($52) ($43)
Future Abandonment and
Reclamation Costs(6)
Mark to McDaniel's cost of ($42) ($35) ($31) ($29)
WGSI Forward Sale
Obligation (7)
Net Asset Value $932 $583 $463 $401
Shares Outstanding 147 147 147 147
(million) - basic
Net Asset Value per Share $6.34 $3.97 $3.15 $2.73
($/Share)
(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 ofUndevelopedLand
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 at10%
Well abandonment costs for $55 $32 $25 $21
developed reserves included in
McDaniel Report
Well abandonment costs for 26 14 10 8
undeveloped reserves included
in McDaniel Report
Well abandonment costs for 81 46 35 30
Total Proved and Probable
reserves included in McDaniel
Report
Estimate of other abandonment 246 141 107 90
and reclamation costs not
included in McDaniel Report
Total estimated future 326 188 142 120
abandonment and reclamation
costs
Salvage value (151) (87) (66) (55)
Abandonment and reclamation 175 101 76 64
costs , net of salvage
Well abandonment costs for (55) (32) (25) (21)
developed reserves included in
McDaniel Report
Estimate of additional future $121 $69 $52 $43
abandonment and reclamation
costs, net of salvage(1)
(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 ($11.04 per BOE) in 2011 on
a proved and probable basis.
2011 FD&A
Costs -
Company
Interest
Reserves
Proved and
($millions Proved Probable
(unaudited), Excluding Excluding
except as Price Proved & Price
noted) Proved Revisions(2) Probable Revisions(3)
F&D Costs,
Excluding
FDC
Exploration $138.6 $138.6 $138.6
and
Development
Capital
Expenditures
(1) $138.6
Reserve 64.1 60.3 88.7
Additions
Including
Revisions -
Bcfe 44.1
F&D - $/Mcfe $2.16 $2.30 $1.56
(4) $3.14
F&D Costs,
Including
FDC
Exploration $138.6 $138.6 $138.6
and
Development
Capital
Expenditures $138.6
Total Change 40.4 35.4 35.4
in FDC 40.4
Total F&D $179.0 $174.0 $174.0
Capital
including
Change in
FDC $179.0
Reserve 64.1 60.3 88.7
Additions
Including
Revisions -
Bcfe 44.1
F&D Costs- $2.80 $2.89 $1.96
$/Mcfe(4) $4.06
FD&A Costs,
Excluding
FDC
Exploration $138.6 $138.6 $138.6
and
Development
Capital
Expenditures $138.6
Net
Acquisitions (33.40) (33.40) (33.40) (33.40)
FD&A Capital $105.23 $105.23 $105.23
Expenditures
Including
Net
Acquisitions $105.23
Reserve 55.7 48.1 76.5
Additions
Including
Net
Acquisitions
- Bcfe 35.8
FD&A Costs - $1.89 $2.19 $1.38
$/Mcfe(4) $2.94
FD&A Costs,
Including
FDC
FD&A Capital $105.23 $105.23 $105.23
Expenditures
Including
Net
Acquisitions $105.23
Total Change 40.4 35.4 35.40
in FDC 40.4
Total FD&A $145.63 $140.63 $140.63
Capital
Including
Change in
FDC $145.63
Reserve 55.7 48.1 76.5
Additions
Including
Net
Acquisitions
- Bcfe 35.8
FD&A Costs $2.62 $2.92 $1.84
Including
FDC -
$/Mcfe(4) $4.07
(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.
SOURCE Perpetual Energy Inc.