News Releases

Perpetual Energy Inc. Releases Second Quarter 2011 Financial And Operating Results And Confirms August 2011 Dividend

CALGARY, Aug. 9, 2011 /CNW/ - (TSX:PMT) - Perpetual Energy Inc. ("Perpetual" or the "Corporation") releases its financial and operating results for the second quarter of 2011. A copy of Perpetual's unaudited interim consolidated financial statements and related notes and management's discussion and analysis ("MD&A") for the three and six months ended June 30, 2011 and 2010 can be obtained through the Corporation's website at and SEDAR at

Perpetual also confirms that its dividend to be paid on September 15, 2011 in respect of income received by Perpetual for the month of August 2011, for shareholders of record on August 31, 2011, will be $0.015 per share. The ex-dividend date is August 29, 2011. The August 2011 dividend brings cumulative dividends (including distributions paid since the inception of Perpetual's predecessor, Paramount Energy Trust) to $14.504 per share. Perpetual reviews dividends on a monthly basis. Future dividends are subject to change as dictated by commodity price markets, operations, capital considerations and future business development opportunities.

Second Quarter Summary

Perpetual's growth and diversification strategies continued to advance according to plan in the second quarter of 2011, despite extremely wet spring weather conditions hampering operations. Outlined below are operational and financial highlights for the second quarter of 2011.

Operational Highlights

  • Average quarterly production increased seven percent to 150.3 MMcfe/d for the second quarter of 2011 from 140.7 MMcfe/d for the first quarter, reflecting the positive results of Perpetual's first quarter capital program.

  • Production volumes decreased nine percent year over year from 165.2 MMcfe/d for the second quarter of 2010 due to the shut-in of approximately 8.0 MMcf/d of raw production and subsequent sale of reserves at Liege ("Liege Assets") and asset dispositions in the Northeast and Athabasca core areas totaling 8.0 MMcf/d of production, partially offset by production additions from successful drilling in the Wilrich formation in the West Central District.

  • Oil and natural gas liquids ("NGL") production increased 45 percent to 1,795 bbl/d (7.2 percent of production) in the second quarter of 2011 from 1,239 bbl/d (4.5 percent of production) in the comparable quarter in 2010. Oil and NGL revenues increased to 20 percent of oil and gas revenues in the second quarter of 2011 from 12 percent in the 2010 quarter.

  • With activities restricted by an exceptionally wet spring break-up, exploration and development capital spending, including Warwick Gas Storage ("WGSI") activities, totaled $14.2 million for the second quarter of 2011, including:

Heavy Oil

In the Mannville area of east central Alberta, Perpetual focused on preliminary development of Cretaceous-aged conventional heavy oil pools geographically synergistic with the Corporation's shallow gas assets. Perpetual drilled two shallow horizontal heavy oil wells at the end of the first quarter. One well, in the Lloyd formation, had an initial oil production rate of 240 bbl/d and averaged 144 bbl/d of oil through the second quarter of 2011. The second well, in the Sparky formation, had an initial oil production rate of 125 bbl/d and averaged 109 bbl/d of oil through the second quarter.

Through the wet weather of the second quarter and into the third quarter, Perpetual has drilled an additional nine horizontal wells into the Sparky pool at an average cost to drill, complete, equip and commence start-up operations of $0.95 million per well. Facility and operations work is ongoing with wells expected to be producing by mid-August.

Exploratory vertical and development horizontal drilling will continue through to the end of the year as capital is focused on growing oil production and reserves in this area, where the Corporation has over 123,000 net acres. Current plans consist of drilling 18 vertical and eight horizontal wells, including both development wells for production as well as low risk exploration wells to evaluate flow characteristics for several pools identified in existing well control.

West Central

With seven horizontal wells drilled, completed and tied in through Perpetual's expanded 16-10 compressor station at Edson over the past year, the Company monitored production performance of the Wilrich horizontal wells relative to the forecast type curve through the second quarter of 2011. The seven wells have averaged initial production and decline performance in line with the Company's type curve for the play.  Natural gas liquids rates were confirmed at 35 to 40 bbl per MMcf. Two Wilrich development wells are planned during the last half of the year to maintain production at the 16-10 compressor station at its maximum capacity of 30 MMcf/d plus associated NGLs. Two additional Wilrich delineation wells will also be drilled during the second half of 2011, targeting expansion of the currently defined Edson Wilrich trend.

Perpetual drilled a vertical well in the Karr area to evaluate liquids-rich gas from multiple horizons including the Montney formation across the Company's acreage. In addition, a horizontal Dunvegan development well targeting liquids-rich gas at 40 bbl per MMcf of NGLs was also drilled from the same surface location during the second quarter. Initial log based indications are positive from both wells and completion operations will be conducted in the third quarter. As a result of this activity, the Company expects to verify as many as four additional Dunvegan and eight Montney horizontal follow-up locations. Although delayed by wet lease conditions caused by inclement weather in late June and early July, the Dunvegan horizontal completion commenced on August 5, 2011, with tie-in operations expected to follow late in the third quarter.

Perpetual obtained approximately 11,840 net acres of prospective Crown lands for a total of $9.4 million in the greater Edson and Elmworth areas during the quarter. Also during the period Perpetual's partner in the Elmworth area completed the earn-in provisions under the farm-in arrangement announced in 2009.


In May, the Corporation received an independent contingent resource report effective April 30, 2011 prepared by McDaniel & Associates Consultants Ltd. ("McDaniel") for the Corporation's acreage in the Panny area of northeast Alberta. McDaniel recognized a best estimate of 618 MMbbl Discovered Bitumen Initially in Place ("DBIIP"). The best estimate gross recoverable contingent resource is estimated at 108 MMbbl. The assignment of gross recoverable contingent resource is based on three vertical and one horizontal well drilled in the first quarter of 2011, approximately 14 legacy wells and the potential application of cyclic steam stimulation. At Panny, Perpetual holds a 100 percent interest.

Subsequent to the end of the quarter, in July, the Corporation received an independent contingent and prospective resource report effective July 31, 2011 prepared by McDaniel for the Corporation's acreage in the South Liege area of northeast Alberta. The resource assignments are only for the South Liege Grosmont and Leduc formations.  McDaniel recognized a best estimate of 288.9 MMbbl DBIIP and a best estimate of 1,166.7 MMbbl Undiscovered Bitumen Initially In Place ("UBIIP") in the South Liege area.  The best estimate contingent resource and additional prospective resource are 57.8 MMbbl and 233.3 MMbbl respectively. McDaniel assigned bitumen resource estimates on the basis of three bitumen evaluation wells that were drilled in the first quarter of 2011 as well as existing legacy gas well control, and assumed that Steam Assisted Gravity Drainage ("SAGD") exploitation in carbonate reservoirs would currently be considered "technology under development". The North Liege property is currently being evaluated and a separate report for North Liege is expected to be provided in the third quarter of 2011. In both South and North Liege, Perpetual holds a 100 percent interest.

Warwick Gas Storage

Perpetual established working gas at 17 Bcf for the second commercial cycle at our Warwick gas storage facility which commenced April 1, 2011. This was more than double the initial test cycle of 7.8 Bcf of working gas marketed for April 2010 to March 2011. Perpetual drilled two horizontal wells at the WGSI facility to date in 2011, including expenditures of $2.8 million in the second quarter, and has an additional well budgeted for the second half of the year to further enhance the working gas capacity at the WGSI facility to continue to work towards the targeted 22 to 25 Bcf.

Viking/Colorado Shale Gas

Perpetual continued its technical evaluation of this shale resource through geochemical and geomechanical analysis and fracture stimulation modeling. A small pilot project utilizing existing vertical wellbores is currently planned for the fourth quarter of 2011 to fracture stimulate the shale gas package and assess flow performance.

Acquisitions and Dispositions

As part of the Company's ongoing asset base evolution and commodity diversification strategy, during the second quarter of 2011, the Corporation sold non-core properties for total proceeds of $22.5 million. These dispositions included a non-core natural gas property and undeveloped Cardium lands in west central Alberta. Perpetual retained all existing Cardium production as well as an additional 24 net sections of undeveloped Cardium lands in the area. Acquisitions were modest and totaled $1.7 million for the three months ended June 30, 2011.

Financial Results

  • Perpetual's natural gas price before derivatives increased three percent for the three months ended June 30, 2011 to $4.01 per Mcf from $3.89 per Mcf in 2010, as compared to a three percent drop in the AECO Monthly Index natural gas price for the same period. The Corporation's realized gas price, including derivatives, was $3.97 per Mcf for the second quarter of 2011, a 25 percent decrease from the comparable quarter in 2010. The 2010 figure included realized gains on derivatives totaling $19.9 million as compared to a loss of $0.5 million for the current period. Perpetual had anticipated a low natural gas price environment in 2011 and crystallized $37.3 million in gains on derivatives in the fourth quarter of 2010 related to 2011 financial natural gas contracts, in order to pre-fund the majority of its capital spending programs for the first three months of 2011. This strategy had the effect of reducing the Corporation's realized gas price in the current quarter.

  • Funds flow netbacks decreased 47 percent to $1.29 per Mcfe in the second quarter of 2011 from $2.43 per Mcfe in the comparable period for 2010, driven primarily by the following:
    • a one-time negative Crown royalty adjustment for $4.5 million related to Perpetual's 2010 and first quarter 2011 gas cost allowance;
    • a delay in the onset of receipt of the gas over bitumen financial solution for eight MMcf/d of deemed production at Liege until June 2011, related to the issuance of the ERCB shut-in order to trigger the Crown royalty reductions;
    • lower realized gains on derivatives; and
    • lower gas prices for the current quarter.

  • As a result of the above, funds flow declined to $17.9 million ($0.12 per common share) from $36.2 million ($0.25 per common share) for the second quarter of 2010. Excluding the one-time royalty adjustment, funds flow for the second quarter would have been $22.4 million ($0.15 per common share).

  • Dividends for the second quarter of 2011 totaled $8.9 million or $0.06 per common share consisting of $0.03 per common share paid on May 16 and $0.015 per common share on June 15 and July 15, representing a payout ratio of 49.8 percent of funds flow.

  • On April 25, 2011 Perpetual announced that the Toronto Stock Exchange accepted Perpetual's Notice of Intention to make a Normal Course Issuer Bid (the "Bid") to purchase for cancellation, from time to time, as Perpetual considers advisable, up to a maximum of 7,415,428 of Perpetual's issued and outstanding common shares. During the second quarter, the Corporation repurchased 767,600 common shares under the Bid for cancellation at an average price of $3.22 per share for a total cost of $2.5 million.

Subsequent Events

  • On August 4, 2011 Perpetual closed the sale of non-core properties in the Grande Prairie area of west central Alberta, which contributed production of 1.6 MMcfe/d in the second quarter, for net cash proceeds of $6.9 million, bringing year to date disposition proceeds to $38 million.

2011 Outlook and Sensitivities

Estimated capital spending of $64 million for the last two quarters of 2011 will be directed primarily to oil and liquids-rich projects with the goal of continuing to accelerate Perpetual's commodity diversification strategy. The Corporation has planned:

  • Two Wilrich development wells to maintain production at the recently expanded 16-10 compressor station at its maximum capacity of 30 MMcf/d plus associated NGLs of 40 bbl per MMcf;
  • Two additional Wilrich delineation wells targeting further expansion of the currently defined Edson Wilrich trend;
  • Completion and tie-in operations for the multi-zone vertical exploration well targeting liquids-rich gas recently drilled at Karr;
  • Multi-stage fracture completion and tie-in operations for the horizontal Dunvegan liquids-rich gas well drilled during the second quarter at Karr;
  • Continued drilling, completion, equipping and production start-up operations on the nine well horizontal program, that began after spring break up, targeting further development of a Sparky heavy oil pool in the Mannville area of east central Alberta. As of the end of June, six wells had been drilled;
  • Development drilling of up to 11 vertical and/or horizontal wells to increase production and recovery from heavy oil pools in the Mannville area including the regional Lloyd formation pool evaluated in the fourth quarter of 2010;
  • A 12-well exploratory program of vertical and horizontal wells designed to test the inflow of seven additional Mannville heavy oil pools.  This program will evaluate the development scope for further 2012 infill drilling;
  • One additional horizontal well at Warwick to further increase the working gas capacity of the gas storage facility;
  • A small scale pilot project utilizing existing wellbores to evaluate various prospective fracture stimulation technologies to define the economic development potential of the Corporation's vast Viking/Colorado shallow shale gas play in east central Alberta; and
  • Reservoir simulation, modeling and pilot application work to assess various technologies for recovery of bitumen from the Bluesky formation at Panny.

The following sensitivity table reflects Perpetual's projected realized gas price, monthly funds flow and payout ratio for the third and fourth quarters of 2011, as well as projected ending 2011 net debt at certain AECO natural gas price levels. These sensitivities incorporate a light oil par price at Edmonton of $91 per bbl, a monthly dividend of $0.015 per share, operating costs of $42 million, cash general and administrative expenses of $14 million and an interest rate on bank debt of four percent.

  Average AECO Monthly Index gas price
for 2011 ($/GJ) (1)
Second half of 2011 funds flow outlook $3.00 $4.00 $5.00
Natural gas production (MMcf/d) 135 135 135
Oil and NGL production (bbl/d) 2,350 2,350 2,350
Realized price ($/Mcfe) (1) 4.18 4.96 5.74
Total funds flow ($millions) (2) 33 49 63
  Per Share ($/Share/month) 0.038 0.056 0.071
Payout ratio (%) (2) 40 27 21
Ending net bank debt ($millions) (2) 128 111 98
Ending net debt ($millions) (2)(3) 512 496 483
Ending net bank debt to annualized funds flow ratio (times) (2)(3) 1.9 1.1 0.8
Ending total net debt to annualized funds flow ratio (times) (2)(3) 7.7 5.0 3.8

(1) The current settled and forward average AECO price for 2011 as of August 8, 2011 is $3.51 per GJ. Realized price is equal to total revenue, excluding revenue from Warwick Gas Storage, divided by Mcf equivalent production.
(2) These are non-GAAP measures; see "Significant accounting policies and non-GAAP measures" in management's discussion and analysis.
(3) Net debt includes convertible debentures and Senior Notes, both measured at principal amount. Ratios are calculated as ending net bank debt or ending net debt divided by annualized funds flow estimated as two times funds flow for the second half of 2011.

Giving effect to the capital activities described above, as well as dispositions, the Corporation expects to exit 2011 with approximately 150 MMcfe/d of production, including over 2,900 bbl/d of oil and NGL (12 percent of total production), thereby strengthening future funds flow.

FINANCIAL AND OPERATING HIGHLIGHTS Three Months Ended June 30 Six Months Ended June 30
($Cdn thousands except volume and per share amounts) 2011 2010 % Change 2011 2010 % Change
Revenue, including realized gains and losses on financial instruments and call option premiums 66,671 83,979 (21) 128,571 215,319 (40)
Funds flow (1) 17,852 36,262 (51) 41,775 120,885 (65)
  Per common share (2) 0.12 0.25 (52) 0.28 0.90 (69)
Net earnings (loss) (5,626) (76,878) (93) (32,886) (56,266) (42)
  Per common share (2) (0.04) (0.54) (93) (0.22) (0.42)  
Dividends 8,887 21,382 (58) 22,234 40,549 (45)
  Per common share (3) 0.06 0.15 (60) 0.15 0.30 (50)
Payout ratio (%) (1) 49.8 59.1 (16) 53.2 33.6 58
Total assets 999,709 1,149,486 (13) 999,709 1,149,486 (13)
Net bank and other debt outstanding (1) 85,624 257,197 (67) 85,624 257,197 (67)
Convertible debentures, at principal amount 234,897 234,897 - 234,897 234,897 -
Senior notes, at principal amount 150,000 - 100 150,000 - 100
Total net debt (1) 470,521 492,094 (4) 470,521 492,094 (4)
Shareholders' equity 148,429 266,256 (44) 148,429 266,256 (44)
Capital expenditures            
  Exploration and development 11,425 20,732 (45) 62,383 49,654 26
  Gas storage 2,759 13,739 (80) 8,343 23,139 (64)
  Acquisitions, net of dispositions (20,777) 78,940 (126) (29,212) 101,090 (129)
  Other 104 174 (40) 203 274 (26)
  Net capital expenditures (6,489) 113,585 (106) 41,717 174,157 (76)
Common shares outstanding (thousands)            
End of period 147,694 143,623 3 147,694 143,623 3
Weighted average 148,187 142,118 4 148,239 134,797 10
Share Options, Restricted Rights and Performance Share Rights outstanding 12,826 8,692 48 12,826 8,692 48
Shares outstanding at August 8, 2011 147,395     147,395    
  Total natural gas, NGLs and oil (Bcfe) (3) 13.7 15.0 (9) 26.4 28.5 (7)
  Daily average natural gas, NGL and oil (MMcfe/d) (3) 150.3 165.2 (9) 145.6 157.2 (7)
  Daily average oil and NGLs (bbl/d) 1,795 1,239 45 1,707 1,139 50
  Gas over bitumen deemed production (MMcf/d) (4) 25.6 26.5 (3) 24.2 26.4 (8)
  Average daily (actual and deemed - MMcfe/d) (4) 175.9 191.7 (8) 169.8 183.6 (8)
  Per common share (cubic feet equivalent/d/share) (2)(3)(4) 1.19 1.35 (12) 1.15 1.29 (11)
Average prices            
  Natural gas, before derivatives ($/Mcf) (5) 4.01 3.89 3 4.06 4.49 (10)
  Natural gas, including derivatives ($/Mcf) (5) 4.58 5.28 (13) 4.63 7.36 (37)
  Oil and NGL ($/bbl) 77.38 67.23 15 72.12 69.42 4
Land (thousands of net acres)            
Undeveloped land holdings 1,834 2,046 (10) 1,834 2,046 (10)
Drilling (wells drilled gross/net)            
  Gas 1/1 2/2 (50)/(50) 5/4.5 26/22.9 (81)/(80)
  Gas storage injection/withdrawal 1/1 2/2 (50)/(50) 2/2 9/9 (78)/(78)
  Oil 6/6 -/- 100/100 15/14 -/- 100/100
  Oil Sands Evaluation -/- -/- -/- 7/7 -/- 100/100
  Dry -/- -/- -/- -/- 1/1 (100)/(100)
  Total 8/8 4/4 100/100 29/27.5 36/32.9 (19)/(17)
  Success rate (%) 100/100 100/100 100/100 100/100 97/96 3/4

(1) These are non-GAAP measures. Please refer to "Significant Accounting Policies and Non-GAAP Measures" included in management's discussion and analysis.
(2) Based on weighted average common shares outstanding for the period.
(3) Converted to natural gas equivalent on the basis of 1 bbl: 6 Mcf
(4) Based on shares outstanding at each dividend date. The deemed production volume describes all gas shut-in or denied production pursuant to a decision report, corresponding order or general bulletin of the Alberta Energy and Utilities Board ("AEUB"), or through correspondence in relation to an AEUB ID 99-1 application. This deemed production volume is not actual gas sales but represents shut-in gas that is the basis of the gas over bitumen financial solution which is received monthly from the Alberta Crown as a reduction against other royalties payable.
(5) Perpetual's commodity hedging strategy employs both financial forward contracts and physical natural gas delivery contracts at fixed prices or price collars. In calculating -the Corporation's natural gas price before financial and physical hedging, Perpetual assumes all natural gas sales based on physical delivery fixed-price or price collar contracts during the period were instead sold at AECO monthly index.
(6) Production amounts are based on Perpetual's interest before royalties.
(7) As Perpetual has an obligation to repay the gas storage arrangement through the delivery of 8 Bcf of natural gas in the first quarter of 2013, it is included in the Corporation's net debt.

Resource Estimates

This news release contains estimates of "Discovered Bitumen Initially in Place ("DBIIP")", "Undiscovered Bitumen Initially In Place" ("UBIIP"), "contingent resources" and "prospective resources". These terms are not, and should not be confused with, oil and gas reserves.  "DBIIP" is defined in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") as 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.  "UBIIP" is defined in the COGE Handbook as 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; the remainder is unrecoverable.  "Contingent resources" are defined in the COGE Handbook as 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.  "Prospective resources" are defined in the COGE Handbook as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects.  Prospective resources have both an associated chance of discovery and a chance of development. There is no certainty that it will be commercially viable to produce any portion of the resources or that the Corporation will produce any portion of the volumes currently classified as "DBIIP" and "contingent resources". There is no certainty that any portion of the UBIIP and prospective resources will be discovered.  If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources or that the Corporation will produce any portion of the volumes currently classified as "UBIIP" and "prospective resources".  "DBIPP", "UBIIP", "contingent resource" and "prospective resource" estimates contained herein are presented as the "best estimate" of the quantity that will or may be recovered. A "best estimate" means that it is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate, and if probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the best estimate. 

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.  In addition, with respect to the disclosed DBIIP and contingent resources at South Liege, there is a significant technical contingency pertaining to the successful implementation of SAGD technology.  The successful implementation of SAGD technology in carbonate reservoirs is a significant contingency associated with these assignments that separate them from typical McMurray clastic SAGD contingent and prospective resources, where the technology has repeatedly been proven effective. In addition to this technical contingency, additional contingencies applicable to the Liege South carbonate resource include being in the early evaluation stage (insufficient delineation), economic concerns (not clear whether a future development project would be economic), regulatory issues (environmental and development applications not yet submitted), as well as lack of corporate intent to develop.  An economic evaluation was not undertaken with respect to the Corporation's resources and therefore all contingent and prospective resources assigned to the Corporation are currently classified as "economic status undetermined".

See the Corporation's MD&A for the three and six months ended June 30, 2011 and 2010, a copy of which is available on Perpetual's SEDAR profile at for further information with respect to resource estimates

Forward Looking Information

Certain information regarding Perpetual in this news release including management's assessment of future plans and operations and including the information contained under the headings "Subsequent Events" and "Outlook and Sensitivities" above may constitute forward-looking statements under applicable securities laws. The forward looking information includes, without limitation, statements regarding future dividends; expected production and timing thereof ; expected working gas capacity at the Corporation's gas storage facility; anticipated operations, drilling, development and the timing thereof; amount, funding, allocation and timing of capital spending; forecast and realized commodity prices, funds flow and payout ratio; projected ending net debt; use of funds flow; marketing and transportation; reserve estimates; and estimated funds flow sensitivity. 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 the Corporation'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 ( and at Perpetual's website ( 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 laws.

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 the Corporation's MD&A.

Mcf equivalent (Mcfe) may be misleading, particularly if used in isolation. In accordance with National Instrument 51-101 ("NI 51-101"), an 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.

Perpetual is a natural gas-focused Canadian Corporation. Perpetual's shares and convertible debentures are listed on the Toronto Stock Exchange under the symbol "PMT" and "PMT.DB.C", "PMT.DB.D" and "PMT.DB.E", respectively. Further information with respect to Perpetual can be found at its website at

The Toronto Stock Exchange has neither approved nor disapproved the information contained herein.





For further information:
Perpetual Energy Inc.
Suite 3200, 605 - 5 Avenue SW  Calgary, Alberta, Canada  T2P 3H5
Telephone:  403 269-4400 Fax: 403 269-4444 Email:
Sue Riddell Rose President and Chief Executive Officer
Cam Sebastian Vice President, Finance and Chief Financial Officer
Claire Gall Investor Relations


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