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PERPETUAL ENERGY INC. RELEASES FIRST QUARTER 2011 FINANCIAL AND OPERATING RESULTS, ANNOUNCES UNDEVELOPED LAND DISPOSITION AND E

^{Published on 2011-05-17 18:40:53 - Market Wire}
 

 - Total production decreased six percent to 140.7 MMcfe/d for the first quarter of 2011 from 149.2 MMcfe/d for the comparable quarter in 2010. Natural gas production volumes decreased eight percent to 131.1 MMcf/d for the three months ended March 31, 2011 from 143.0 MMcf/d for the first quarter of 2010, primarily due to the early shut-in of approximately 5.7 MMcf/d of production and subsequent sale of reserves at Liege and non-core property dispositions, partially offset by the Edson Acquisition completed on April 1, 2010 and drilling activity in west central Alberta. Oil and NGL production volumes increased 587 bbl/d or 57 percent to 1,620 bbl/d from the first three months of 2010 due to positive results from capital spending in the Edson and Carrot Creek areas targeting oil and liquids-rich gas and an increased focus on development of several heavy oil pools in eastern Alberta, partially offset by property dispositions. - Exploration and development capital spending totaled $51.0 million for the first quarter of 2011, including: - Edson Wilrich: Perpetual drilled and completed two wells (2.0 net) and completed an additional two wells (1.5 net) that were drilled in the fourth quarter of 2010. Additional costs were incurred to complete the expansion of the 16-10 compressor station, adding 20 MMcf/d of capacity; - Cardium: Four gross wells (3.0 net) were drilled at Carrot Creek, targeting further development of the Cardium light oil play; - Elmworth Montney: One of Perpetual's three horizontal wells (1.4 net) was tied in by the operator, and will be tested during the second quarter; - Bitumen: Nine bitumen evaluation wells were drilled and cored at four of Perpetual's bitumen properties in northeast Alberta; - Heavy oil: Drilling activity in the Lloyd and Sparky channels in the Mannville area of Alberta continued in the first quarter, growing production from this area to 500 bbl/d as at March 31, 2011, and further development and downspacing expenditures are planned for the second quarter; - Viking/Colorado shale gas: Perpetual continued its technical evaluation of this shale resource through geochemical and geomechanical analysis and fracture stimulation modeling; and - Shallow gas: The Corporation continued to mitigate decline rates on its legacy asset base through recompletions and strategic drilling. - Gas storage spending, including the completion of facility construction, the drilling of one additional horizontal well and a portion of a second well, totaled $5.6 million for the current period. - Perpetual's natural gas storage facility at Warwick ("WGSI") successfully completed its first test cycle March 31, 2011 with withdrawal of 7.8 Bcf. Both the reservoir and facility performance exceeded preliminary expectations. Reservoir modeling, combined with test information from the new horizontal well drilled in the first quarter of 2011, has confirmed performance of the reservoir, wells and facility such that WGSI has established its working gas capacity at 17 Bcf for its second commercial storage cycle which commenced April 1, 2011. Perpetual has budgeted to complete the drilling of the horizontal well, which was spud prior to quarter end, and drill one additional well in the remainder of 2011. The additional horizontal well is expected to further enhance the working gas capacity at the WGSI facility to continue to work towards the targeted 22 to 25 Bcf. 

 - Perpetual's natural gas price before derivatives decreased 20 percent for the three months ended March 31, 2011 to $4.12 per Mcf from $5.16 per Mcf in 2010, as compared to a 30 percent drop in the AECO Monthly Index natural gas price for the same period. The Corporation's realized gas price was $4.21 per Mcf for the first quarter of 2011, a 56 percent decrease from the comparable quarter in 2010. The 2010 figure included realized gains on derivatives totaling $56.4 million as compared to gains of $1.0 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 70 percent to $1.89 per Mcfe in the first quarter of 2011 from $6.31 per Mcfe in the comparable period for 2010, driven primarily by lower realized gains on derivatives and lower gas prices for the current quarter. As a result of this decrease, funds flow declined to $23.9 million ($0.16 per common share) from $84.6 million ($0.66 per common share) for the first quarter of 2010. - On March 15, 2011 the Corporation issued $150.0 million of seven-year senior unsecured notes (the "Senior Notes") for net proceeds of $146.3 million after issue costs. The Senior Notes are direct senior unsecured obligations of Perpetual ranking pari passu with all other present and future unsecured and unsubordinated indebtedness of the Corporation. The Senior Notes bear interest at 8.75%, payable semi- annually, and mature on March 15, 2018. - Dividends for the first quarter of 2011 totaled $13.3 million or $0.09 per common share consisting of $0.03 per common share paid on February 15, March 15, and April 15 representing a payout ratio of 59.3 percent of funds flow. - Property dispositions totaled $8.5 million for the three months ended March 31, 2011 The non-core properties disposed were located in the Athabasca core area, and comprised approximately 2 MMcfe/d of production. 

 - 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. Purchases of common shares will be made on the open market through the Toronto Stock Exchange. The maximum number of common shares allowed to be purchased pursuant to the Bid represents approximately five percent of the common shares issued and outstanding on the date of the announcement. - On May 10, 2011, the Alberta Energy Resources Conservation Board ("ERCB") released Decision 2011 ABERCB 012: Athabasca Oil Sands Corp., Requests for Interim Shut-in of Gas, Liege Field, Athabasca Oil Sands Area (the "Interim Shut-in Decision"). The Interim Shut-in Decision orders shut-in approximately 321 wells in the Legend/Liege areas effective May 31, 2010. Perpetual holds a 100% interest in one of those wells. In November of 2010, Perpetual disposed of some 70 wells also affected by the Interim Shut-in Decision, but retained operatorship in order to be eligible to receive gas over bitumen financial solution royalty adjustments. Perpetual therefore believes that the Interim Shut-in Decision will not materially affect Perpetual's future funds flow. - In May, the Corporation received an independent contingent resource report 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 recoverable contingent resource is estimated at 108 MMbbl. The assignment of 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. - On May 16, Perpetual closed the sale of 21 gross (12 net sections) of undeveloped Cardium rights in the Carrot Creek area for $14 million cash bringing total disposition proceeds to $22.5 million in 2011. Proceeds will be directed towards the Corporation's expanded 2011 capital program. Perpetual retained all existing Cardium production as well as an additional 24 net sections of undeveloped Cardium lands in the greater Carrot creek area. 

 - Two net Wilrich development wells to maintain production at the recently expanded 16-10 compressor station at its maximum capacity of 30 MMcf/d; - Two additional Wilrich delineation wells targeting further expansion of the currently defined Edson prospect inventory; - One net exploration well targeting the Halfway and Montney formations and one net horizontal well targeting the Dunvegan formation in the Karr area in West Central Alberta to establish production and reserves, and preserve lands; - An eight well horizontal program, beginning after spring break up, targeting further development of a Sparky heavy oil pool in the Mannville area of east central Alberta; - Development drilling of 26 deviated wells to increase production and recovery from the regional Lloyd formation pool evaluated in the fourth quarter of 2010; - A ten 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 pilot project 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 and modeling to assess various technologies for recovery of bitumen from the Bluesky formation at Panny. 

 Average AECO Monthly Index gas price for 2011 ($/GJ) Full year 2011 funds flow outlook $3.00 $4.00 $5.00 ------------------------------------------------------------------------- Natural gas production (MMcf/d) 135 135 135 Oil and NGL production (bbl/d) 2,150 2,150 2,150 Realized gas price ($/Mcfe)(1) 4.53 5.27 6.00 Total funds flow ($millions)(2) 86 120 149 Per Share ($/Share/month) 0.048 0.067 0.084 Payout ratio (%)(2) 41 30 24 Ending net bank debt ($millions)(2) 128 94 64 Ending net debt ($millions)(2) 513 479 449 Ending net bank debt to funds flow ratio (times) 1.7 0.6 0.2 Ending total net debt to funds flow ratio (times) 7.1 3.9 2.7 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) The current settled and forward average AECO price for 2011 as of May 16, 2011 is $3.70 per GJ. These are non-GAAP measures; see "Significant accounting policies and non-GAAP measures" in management's discussion and analysis. (2) Calculated as ending net debt (including convertible debentures and Senior Notes) divided by annual funds flow. 

 FINANCIAL AND OPERATING HIGHLIGHTS ($Cdn thousands except volume Three Months Ended March 31 and per Share amounts) 2011 2010 % Change ------------------------------------------------------------------------- Financial Revenue(1) 61,900 131,340 (53) Funds flow(2) 23,923 84,623 (72) Per Share(3) 0.16 0.66 (76) Cash flow provided by operating activities 15,146 62,662 (76) Per Share(3) 0.10 0.64 (84) Net earnings (loss) (27,260) 20,612 (232) Per Share(3) (0.18) 0.16 (213) Dividends 13,347 19,167 (30) Per Share(4) 0.09 0.15 (40) Payout ratio (%)(2) 55.8 22.7 146 ------------------------------------------------------------------------- Total assets 1,019,987 1,160,225 (12) Net bank debt outstanding(2) 98,763 259,552 (62) Senior notes, at principal amount 150,000 - 100 Convertible debentures, at principal amount 234,897 230,168 2 Total net debt(2) 483,660 489,720 (1) Shareholders' equity 163,656 (916,673) 82 ------------------------------------------------------------------------- Capital expenditures Exploration, development and gas storage 56,542 38,525 47 Acquisitions, net of dispositions (8,435) 21,947 (138) Other 99 100 (1) Net capital expenditures 48,206 60,369 (20) ------------------------------------------------------------------------- Common Shares outstanding (thousands) End of period 148,309 128,591 (15) Weighted average 148,293 127,394 (16) May 12, 2011 148,319 ------------------------------------------------------------------------- Operating Daily average production Natural gas (MMcf/d)(6) 131.1 143.0 (8) Oil and NGL (bbl/d)(6) 1,620 1,033 57 Total (MMcfe/d)(6) 140.7 149.2 (6) Gas over bitumen deemed production (MMcf/d)(5) 22.7 26.3 (14) Average daily (actual and deemed - MMcfe/d)(5) 163.4 175.5 (7) Per Common Share (cubic feet equivalent/d/Share)(3) 1.10 1.38 (20) Average prices Natural gas, before derivatives ($/Mcf) 4.12 5.16 (20) Natural gas, including derivatives ($/Mcf) 4.21 9.55 (56) Oil and NGL ($/bbl) 66.23 72.07 (8) ------------------------------------------------------------------------- Land (thousands of net acres) Undeveloped land holdings 1,876 2,093 (10) ------------------------------------------------------------------------- Drilling (wells drilled gross/net) Gas 4/3.5 30/27 (87)/(87) Gas storage 1/1 1/1 -/- Oil 9/8.0 -/- 100/100 Oil sands evaluation 7/7.0 -/- 100/100 Total 21/19.5 31/28 (32)/(30) Success rate (%) 100/100 97/96 3/4 ------------------------------------------------------------------------- (1) Revenue includes realized gains (losses) on derivatives and call option premiums received. (2) These are non-GAAP measures. Please refer to "Significant Accounting Policies and Non-GAAP Measures" included in management's discussion and analysis. (3) Based on weighted average Common Shares outstanding for the period. (4) Based on Common Shares outstanding at each dividend date. (5) 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. (6) Production amounts are based on the Trust's interest before royalties.