PGH Payments Group Holding GmbH and Co KGaA

Pengrowth Energy Trust announces unaudited financial, operating and reserve results for year ended December 31, 2004 Stock Symbol: PGF.A/PGF.B, TSX; PGH, NYSE CALGARY, Feb. 28 /PRNewswire-FirstCall/ -- Pengrowth Corporation ("Pengrowth"), administrator of Pengrowth Energy Trust (the "Trust"), is pleased to report operating and financial results for the fourth quarter and year ended December 31, 2004 as well as selected information from Pengrowth's independent engineering reserve report effective December 31, 2004. 2004 KEY ACHIEVEMENTS - Fourth quarter oil and gas sales increased 42% to $218.8 million in 2004 from $154.1 million in 2003 resulting in full year 2004 oil and gas sales of $801.2 million, up 16% from $691.0 million in 2003. - On May 31, 2004 Pengrowth acquired oil and natural gas assets in Alberta and Saskatchewan from a subsidiary of Murphy Oil Corporation (the "Murphy Assets") for $550.8 million. These properties increased Pengrowth's proved plus probable reserves by 46.1 million barrels of oil equivalent (boe) and increased daily production by approximately 14,600 barrels of oil equivalent per day (boepd), representing an increase of 25% from Pengrowth's opening reserve base and a contribution of approximately 31% to average daily production during the fourth quarter 2004. - On July 27, 2004 Pengrowth trust units were reclassified as Class A and Class B trust units. The reclassification was initiated in response to restrictions on foreign ownership in mutual fund trusts. On December 6, 2004, subsequent to the reclassification, the Minister of Finance announced his intention to defer implementation of legislation proposed in the March 23, 2004 Federal Budget that would have further restricted foreign ownership to allow further consultation with industry participants. The reclassification positions Pengrowth to actively manage the level of foreign ownership in the Trust to comply with existing and possible future legislative requirements, thereby ensuring the Trust's continued status as a mutual fund trust. - Pengrowth ended the year with proved plus probable reserves of 218.6 mmboe compared to 184.4 mmboe at year-end 2003. This represents an increase of 34 mmboe or over 18% resulting from acquisitions of 48 mmboe, largely attributable to the Murphy Assets, and 6 mmboe of positive reserve revisions and additions, offset by 20 mmboe of production. - Pengrowth raised a total of $509.8 million in new equity during 2004, including a public offering of 10.9 million trust units on March 23, 2004 for gross proceeds of $200.6 million ($189.9 million net proceeds) and a public offering of 16.0 million Class B trust units for gross proceeds of $298.9 million ($283.3 million net proceeds) on December 30, 2004. An additional $36.6 million in proceeds was raised under the Distribution Reinvestment Plan("DRIP")and the employee trust unit option and rights plans. - With the closing of the Class B trust unit offering at the end of 2004, Pengrowth's financial position remained strong with a long-term debt to debt-plus-equity ratio at a conservative 19% of total consolidated capitalization at book, providing Pengrowth with sufficient borrowing capacity to fully fund its 2005 capital requirements. The following table and discussion includes non-GAAP financial measures. Certain non-GAAP financial measures are used to facilitate the evaluation of underlying trends that can be compared with prior periods and may not be comparable to results presented by other companies (see Non-GAAP Financial Measures). Financial and Operating Highlights (thousands, except Three Months ended per unit amounts) December 31 % 2004 2003 Change Income Statement Oil and gas sales $ 218,835 $ 154,139(x) 42 Net income $ 31,138 $ 37,355 (17) Net income per unit $ 0.23 $ 0.31 (26) Distributable cash $ 96,466 $ 71,469 35 Actual distributions paid or declared per unit $ 0.69 $ 0.63 10 Weighted average number of trust units outstanding 136,916 122,326 12 Balance Sheet Working capital Property, plant and equipment and other assets Long-term debt Unitholders' equity Unitholders' equity per unit Number of units outstanding at year end Daily Production Crude oil (barrels) 20,118 22,193 (9) Heavy oil (barrels) 5,819 0 Natural gas (thousands of cubic feet) 156,621 117,315 34 Natural gas liquids (barrels) 5,385 5,907 (9) Total production (BOE) 6:1 57,425 47,653 21 Total production (mboe) 6:1 5,283 4,384 21 Change in production (year over year) (%) 21% (9%) Production Profile Crude oil 35% 47% Heavy oil 10% 0% Natural gas 46% 41% Natural gas liquids 9% 12% Average Prices Crude oil (per barrel) $ 44.76 $ 38.29(x) 17 Heavy oil (per barrel) $ 26.99 $ - Natural gas (per mcf) $ 7.02 $ 5.50(x) 28 Natural gas liquids (per barrel) $ 48.04 $ 35.52(x) 35 Average price per BOE 6:1 $ 41.42 $ 35.16(x) 18 Proved Plus Probable Reserves Crude oil (mbbls) Heavy oil (mbbls) Natural gas (bcf) Natural gas liquids (mbbls) Total oil equivalent (mboe) (thousands, except Twelve Months ended per unit amounts) December 31 % 2004 2003 Change Income Statement Oil and gas sales $ 801,200 $ 691,020(x) 16 Net income $ 153,745 $ 189,297 (19) Net income per unit $ 1.15 $ 1.63 (29) Distributable cash $ 363,061 $ 313,415 16 Actual distributions paid or declared per unit $ 2.63 $ 2.68 (2) Weighted average number of trust units outstanding 133,395 115,912 15 Balance Sheet Working capital $ (78,546) $ 12,966 (706) Property, plant and equipment and other assets $ 1,989,288 $ 1,530,359 30 Long-term debt $ 345,400 $ 259,300 33 Unitholders' equity $ 1,462,211 $ 1,159,433 26 Unitholders' equity per unit $ 9.56 $ 9.36 2 Number of units outstanding at year end 152,973 123,874 23 Daily Production Crude oil (barrels) 20,817 23,337 (11) Heavy oil (barrels) 3,558 0 Natural gas (thousands of cubic feet) 144,277 119,842 20 Natural gas liquids (barrels) 5,281 5,722 (8) Total production (BOE) 6:1 53,702 49,033 10 Total production (mboe) 6:1 19,655 17,897 10 Change in production (year over year) (%) 10% 12% Production Profile Crude oil 39% 47% Heavy oil 6% 0% Natural gas 45% 41% Natural gas liquids 10% 12% Average Prices Crude oil (per barrel) $ 43.21 $ 40.85(x) 6 Heavy oil (per barrel) $ 32.45 $ - Natural gas (per mcf) $ 6.80 $ 6.35(x) 7 Natural gas liquids (per barrel) $ 42.21 $ 35.54(x) 19 Average price per BOE 6:1 $ 40.76 $ 38.61(x) 6 Proved Plus Probable Reserves Crude oil (mbbls) 94,066 97,360 (3) Heavy oil (mbbls) 18,245 - Natural gas (bcf) 521 413 26 Natural gas liquids (mbbls) 19,395 18,250 6 Total oil equivalent (mboe) 218,613 184,416 19 (x) Restated to conform to presentation adopted in the current year Note Regarding Forward-Looking Statements The following discussion and analysis contains forward-looking statements. These statements relate to future events or our future performance. In some cases, you can identify forward-looking statements by terminology such as "may", "will", "should", "expect", "plan", "anticipate", "believe", "estimate", "predict", "potential", "continue", or the negative of these terms or other comparable terminology. These statements are only predictions. A number of factors may cause actual results to vary materially from these estimates. Actual events or results may differ materially. In addition, this discussion contains forward-looking statements attributed to third party industry sources. Readers should not place undue reliance on these forward- looking statements. The amounts recorded for depletion, depreciation, amortization of injectants and the provision for asset retirement obligations are based on estimates. The ceiling test calculation is based on estimates of proved reserves, production rates, oil and natural gas prices, future costs and other relevant assumptions. As required by National Instrument 51-101 ("NI 51-101"), Pengrowth uses independent qualified reserve evaluators in the preparation of reserve evaluations. By their nature, these estimates are subject to measurement uncertainty and changes in these estimates may impact the consolidated financial statements of future periods. Non-GAAP Financial Measures This press release refers to certain financial measures that are not determined in accordance with Canadian Generally Accepted Accounting Principles ("GAAP") in Canada or the United States. These measures do not have standardized meanings and may not be comparable to similar measures presented by other trusts or corporations. Although such measures as Distributable cash, Distributable cash before withholding and Operating netbacks do not have standardized meanings prescribed by GAAP. Distributable cash is determined by reference to the Distributions and Taxability of Distributions section of this release while the remaining measures are determined by reference to our financial statements. We discuss these measures, which have been applied on a consistent basis, because we believe that they facilitate the understanding of the results of our operations and financial position. Conversion and currency When converting natural gas to equivalent barrels of oil within this discussion, Pengrowth has adopted the international standard of 6 thousand cubic feet (mcf) to one barrel of oil equivalent (boe). Barrels of oil equivalent may be misleading, particularly if used in isolation; a conversion ratio of 6 mcf of natural gas to one boe is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All amounts are stated in Canadian dollars unless otherwise specified. 2004 YEAR OVERVIEW Robust commodity prices and seven months of incremental production from the Murphy Assets combined for another solid year of cash flow generation for Pengrowth. Funds generated from operations were up 13% from 2003 leading to an increase of 16% in the level of Distributable cash for the year ended December 31, 2004 compared to 2003. Financial hedging losses of $69.1 million on crude oil and natural gas offset some of the positive impact of the high benchmark prices for the year as did the 7% depreciation of the U.S. dollar relative to the Canadian dollar. Pengrowth also achieved strong results from its 2004 capital expenditure program. During the year Pengrowth spent a combined total of $161.1 million on maintenance and development projects with approximately $112.1 million of that amount directed specifically towards development activities which resulted in the addition of new proved plus probable reserves of 1.4 mmboe and the reclassification of 6.6 mmboe of reserves from the proved undeveloped to the proved developed category. Approximately 46% of expenditures were funded through a combination of the 10% holdback from distributions and equity proceeds received from the DRIP and the employee trust unit option and rights incentive plans. Distributable cash to unitholders increased to $363 million in 2004 from $313 million in 2003. Actual distributions paid or declared in respect of the 2004 production year were $2.63 per trust unit, a marginal decrease of 1.9% from $2.68 per trust unit in 2003. Net income decreased to $154 million in 2004 ($31.1 million in the fourth quarter) from $189 million in 2003 ($37.4 million in the fourth quarter). The reduction in income resulted largely from lower unrealized foreign exchange gains on U.S. dollar debt (2004 - $18.9 million; 2003 - $30.9 million) and a higher per boe depletion rate in 2004 versus 2003 (2004 - $12.58 per boe; 2003 - $10.35 per boe). The 22% increase in the depletion rate per boe is reflective of the relatively higher cost of 2004 reserve additions compared to the lower cost of older reserves. In 2004, Pengrowth recognized a future income tax liability on the acquisition of the Murphy Assets. Net income in 2004 includes a $15.6 million future income tax expense which represents an increase in the future income tax liability subsequent to the acquisition. During 2004 Pengrowth realized an average commodity price of $40.76 per boe, an increase of 6% versus the average realized commodity price of $38.61 in 2003. In the fourth quarter the average realized commodity price was $41.42, an increase of 18% versus the fourth quarter of 2003. 2004 OPERATIONAL REVIEW Production Pengrowth exited the year with fourth quarter production of 2004 of 57,425 boepd, an increase of 21% over the same period of 2003. Full year average production increased 10% to 53,702 boepd in 2004 compared to 49,033 boepd in 2003. This increase is attributable mainly to the mid-year acquisition of the Murphy Assets which added approximately 14,600 boepd commencing in June, comprised mainly of heavy oil and natural gas. Daily Production Volume 2004 2003 % Change ------------------------------------------------------------------------- Light crude oil (bbl) 20,817 23,337 (11) Heavy oil (bbl) 3,558 - Natural gas (mcf) 144,277 119,842 20 Natural gas liquids (bbl) 5,281 5,722 (8) Total production (boe) 53,702 49,033 10 Pricing and Commodity Price Hedging The increase in U.S. dollar based prices for North American crude oil and natural gas were partially offset by the negative impact of the rising Canadian dollar relative to the U.S. dollar and hedging losses. Benchmark Pricing 2004 2003 % Change ------------------------------------------------------------------------- WTI crude oil ($U.S./bbl) $ 37.35 $ 30.99 21 AECO (monthly) natural gas ($/mcf) $ 6.58 $ 6.70 (2) NYMEX (Henry Hub close) natural gas ($U.S./MMbtu) $ 6.26 $ 5.39 16 Currency ($U.S./$Cdn) $ 0.77 $ 0.71 (7) Pengrowth's Average Realized Prices ------------------------------------------------------------------------- (Adjusted for Hedging) 2004 2003 % Change ------------------------------------------------------------------------- Crude oil ($/bbl) $ 43.21 $ 40.85 6 Heavy oil ($/bbl) $ 32.45 - Natural gas ($/mcf) $ 6.80 $ 6.35 7 Natural gas liquids ($/bbl) $ 42.21 $ 35.54 19 Average price ($/boe) 6:1 $ 40.76 $ 38.61 6 Oil and Gas Sales ($ millions) ------------------------------------------------------------------------- 2004 2003 % Change ------------------------------------------------------------------------- Crude oil $ 329.2 $ 348.0 (5) Heavy oil 42.3 - Natural gas 359.3 277.8 29 Natural gas liquids 81.6 74.2 10 Less: gross overriding royalties (14.6) (11.7) 24 Gas marketing, brokering income and sulphur 3.4 2.7 27 ------------------------------------------------------------------------- Total oil and gas sales $ 801.2 $ 691.0 16 ------------------------------------------------------------------------- The following table illustrates in detail the effect of changes in prices and volumes on the components of oil and gas sales including the impact of hedges which expired during the period. Oil and Gas Sales - Price and volume analysis (millions Light Heavy Natural of dollars) Oil Oil Gas NGL GORR Other Total ------------------------------------------------------------------------- Year ended December 31, 2003 $348.0 - $277.8 $ 74.2 ($11.7) $2.7 $691.0 Effect of changes in sales volumes (36.8) 42.3 57.6 (5.5) - - 57.6 Effect of increase in product prices 18.0 - 23.9 12.9 - - 54.8 Other - - - - (2.9) 0.7 (2.2) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Year end December 31, 2004 $329.2 $ 42.3 $359.3 $ 81.6 ($14.6) $ 3.4 $801.2 ------------------------------------------------------------------------- Royalties Crown royalties (net of incentives), freehold royalties and mineral taxes increased to $145.8 million in 2004 from $114.9 million in 2003. Royalties as a percentage of oil and gas sales increased to 18.2% in 2004 from 16.6% in 2003 as a result of higher commodity prices. Also affecting royalties was an adjustment to the Enhanced Oil Recovery relief as a result of solvent injection costs being $6.5 million lower at Judy Creek due to shutdowns and changes in injection strategy. Operating Expenses Operating expenses increased to $159.7 million in 2004 compared to $149.0 million in 2003. The increase is due mainly to the purchase of the Murphy Assets offset in part by a decrease in operating costs at the Sable Offshore Energy Project ("SOEP") due to the elimination of processing fees as a result of the purchase of the processing facilities in May and December of 2003. Operating costs per boe decreased to $8.13 per boe in 2004 from $8.33 per boe in 2003. The decrease was due mainly to the elimination of SOEP processing fees, offset in part by the impact of production declines at a number of Pengrowth's properties and general cost increases in the industry. Amortization of Injectants for Miscible Floods The cost of injectants (primarily ethane and methane) purchased for injection in miscible flood programs is amortized over the period of expected future economic benefit. Prior to 2005, the expected future economic benefit from injection was estimated at 30 months, based on the results of previous flood patterns. Commencing in 2005, the response period for additional new patterns being developed is expected to be somewhat shorter relative to the historical miscible patterns in the project. Accordingly, the cost of injectants purchased in 2005 will be amortized over a 24 month period while costs incurred for the purchase of injectants in prior periods will continue to be amortized over 30 months. The total cost of purchased injectants decreased to $20.4 million in 2004 from $23.0 million in 2003. In 2004, $19.7 million was amortized and deducted from Distributable cash (2003 - $32.5 million). As at December 31, 2004, Pengrowth had deferred injectant costs of $25.0 million, which will be amortized and charged against Distributable cash of future periods. The value of Pengrowth's proprietary injectants is not recorded until reproduced from the flood and sold, although the cost of producing these injectants is included in operating costs. Pengrowth currently anticipates lower injection volumes through 2005, however this is expected to be offset somewhat by higher forecast prices for natural gas and ethane and the increase in Pengrowth's working interest in Swan Hills resulting in anticipated total injectant costs for 2005 relatively unchanged from those incurred in 2004. The amount of injectants amortized against net income is expected to increase in 2005 as a result of a shorter amortization period and the acquisition of the additional interest in Swan Hills Unit No.1. Netbacks There is no standardized measure of operating netbacks and therefore operating netbacks, as presented below, may not be comparable to similar measures presented by other companies. Certain assumptions have been made in allocating operating expenses, other production income, other income and royalty injection credits between light crude, heavy oil, natural gas and natural gas liquids production. Pengrowth recorded an operating netback of $24.51 per boe in 2004 ($24.31 in the fourth quarter) compared to $22.17 in 2003 ($20.43 in the fourth quarter), mainly due to higher average commodity prices in 2004. Three Months Ended Twelve Months Ended Dec 31, Dec 31, Dec 31, Dec 31, 2004 2003 2004 2003 ------------------------------------------------------------------------- Light Crude Netbacks ($ per Bbl) Sales Price $ 44.76 $ 38.29 $ 43.21 $ 40.85 Other production income 0.48 0.25 0.45 0.31 GORR Royalties (0.90) (0.54) (0.76) (0.54) ------------------------------------------------------------------------- 44.34 38.00 42.90 40.62 Other income 0.51 0.43 0.46 0.35 Crown and Freehold Royalties (8.75) (2.77) (6.86) (4.94) Operating costs (9.17) (9.65) (9.31) (8.60) Transportation Costs (0.23) (0.21) (0.23) (0.21) Amortization of injectants (2.67) (2.96) (2.58) (3.82) ------------------------------------------------------------------------- Operating Netback $ 24.03 $ 22.84 $ 24.38 $ 23.40 ------------------------------------------------------------------------- Three Months Ended Twelve Months Ended Dec 31, Dec 31, Dec 31, Dec 31, 2004 2003 2004 2003 ------------------------------------------------------------------------- Heavy Oil Netbacks ($ per Bbl) ------------------------------------------------------------------------- Sales Price $ 26.99 $ - $ 32.45 $ - GORR Royalties (0.27) - (0.21) - ------------------------------------------------------------------------- 26.72 - 32.24 - Crown and Freehold Royalties (3.92) - (4.66) - Operating costs (9.44) - (9.85) - ------------------------------------------------------------------------- Operating Netback $ 13.36 $ - $ 17.73 - ------------------------------------------------------------------------- Natural Gas Netbacks ($ per Mcf) ------------------------------------------------------------------------- Sales Price $ 7.02 $ 5.50 $ 6.80 $ 6.35 GORR Royalties (0.14) (0.15) (0.13) (0.12) ------------------------------------------------------------------------- 6.88 5.35 6.67 6.23 Other income 0.24 0.17 0.20 0.17 Crown and Freehold Royalties (1.20) (0.87) (1.13) (1.06) Operating costs (1.16) (1.32) (1.15) (1.31) Transportation Costs (0.14) (0.15) (0.12) (0.14) ------------------------------------------------------------------------- Operating Netback $ 4.62 $ 3.18 $ 4.47 $ 3.89 ------------------------------------------------------------------------- NGL Netbacks ($ per Bbl) ------------------------------------------------------------------------- Sales Price $ 48.04 $ 35.52 $ 42.21 $ 35.54 GORR Royalties (1.02) (0.92) (0.92) (0.87) ------------------------------------------------------------------------- 47.02 34.60 41.29 34.67 Crown and Freehold Royalties (18.35) (9.38) (14.51) (12.56) Operating costs (7.87) (9.46) (7.94) (8.94) Transportation Costs (0.10) (0.07) (0.10) (0.08) ------------------------------------------------------------------------- Operating Netback $ 20.70 $ 15.69 $ 18.74 $ 13.09 ------------------------------------------------------------------------- Combined Netbacks ($ per Bbl) ------------------------------------------------------------------------- Sales Price $ 42.08 $ 35.78 $ 41.33 $ 39.11 Other production income 0.17 0.12 0.17 0.15 GORR Royalties (0.83) (0.74) (0.74) (0.65) ------------------------------------------------------------------------- 41.42 35.16 40.76 38.61 Other income 0.83 0.63 0.72 0.59 Crown and Freehold Royalties (8.47) (4.60) (7.42) (6.42) Operating costs (8.06) (8.91) (8.13) (8.33) Transportation Costs (0.47) (0.47) (0.42) (0.46) Amortization of injectants (0.94) (1.38) (1.00) (1.82) ------------------------------------------------------------------------- Operating Netback $ 24.31 $ 20.43 $ 24.51 $ 22.17 ------------------------------------------------------------------------- Reserves (Development and Acquisition) Based on an independent engineering evaluation conducted by Gilbert Laustsen Jung Associates Ltd. (GLJ) effective December 31, 2004 and prepared in accordance with NI 51-101, Pengrowth had proved plus probable reserves of 218.6 mmboe compared to 184.4 mmboe at year end 2003. This represents an increase of 34 mmboe resulting from acquisitions of 48 mmboe, largely attributable to the Murphy Assets, and 6 mmboe of positive reserve revisions and additions, offset by 20 mmboe of production. Proved producing reserves are estimated at 142 mmboe and represent 65% of proved plus probable reserves and total proved reserves of 175 mmboe account for 80% of proved plus probable reserves. These percentages compare to 64% and 81% for 2003, respectively. Using a 10% discount factor and GLJ January 1, 2005 forecast pricing, the proved producing reserves account for 71% of the proved plus probable value while the total proved reserves account for 84% of the proved plus probable value. Using a 6:1 boe conversion rate for natural gas, approximately 43% of Pengrowth's reserves are light/medium crude oil, 8% are heavy oil (acquired from Murphy), 40% are natural gas and 9% are Natural Gas Liquids (NGLs). Pengrowth remains a geographically diversified energy trust with properties located across Canada in the provinces of British Columbia, Alberta, Saskatchewan and offshore Nova Scotia. On a proved plus probable reserve basis, the Alberta, Saskatchewan, British Columbia and offshore Nova Scotia holdings account for 68%, 14%, 10%, and 8% of reserves reported by GLJ, respectively. Reserves Summary 2004 Company Interest (Working Interest plus Royalty Interest before the deduction of Royalty Burdens Payable) Oil Oil Light and Equi- Equi- Medium Heavy Natural valent valent Crude Oil Oil NGLs Gas 2004 2003 mbbl mbbl mbbl bcf mboe mboe ------------------------------------------------------------------------- Proved Producing 57,654 12,592 12,841 355.6 142,353 117,937 Proved Developed Non-Producing 548 72 376 23.0 4,825 2,680 Proved Undeveloped 15,973 1,958 2,271 48.7 28,324 28,442 ------------------------------------------------------------------------- Total Proved 74,175 14,622 15,488 427.3 175,502 149,060 ------------------------------------------------------------------------- Proved plus Probable 94,066 18,245 19,395 521.4 218,613 184,416 ------------------------------------------------------------------------- Net Interest (Working Interest less Royalties Payable) Oil Oil Light and Equi- Equi- Medium Heavy Natural valent valent Crude Oil Oil NGLs Gas 2004 2003 mbbl mbbl mbbl bcf mboe mboe ------------------------------------------------------------------------- Proved Producing 49,212 11,037 9,037 285.1 116,798 95,760 Proved Developed Non-Producing 465 62 292 17.6 3,757 2,120 Proved Undeveloped 13,894 1,633 1,644 38.7 23,616 24,478 ------------------------------------------------------------------------- Total Proved 63,572 12,733 10,974 341.4 144,171 122,357 ------------------------------------------------------------------------- Proved plus Probable 80,443 15,798 13,819 415.4 179,298 151,060 ------------------------------------------------------------------------- Reserve Reconciliation Pengrowth added 54 mmboe of proved plus probable reserves during 2004, replacing 2004 production by 270%. The acquisition of the Murphy Assets, which included heavy oil along the Alberta-Saskatchewan border and light oil and natural gas in southern and west central Alberta, accounted for approximately 85% of the reserve increase. The balance was due to drilling additions, mainly in Southeast Alberta shallow gas, and performance related positive revisions, mainly in the Weyburn Unit CO2 miscible flood and the SOEP Alma field. Company Interest Volumes (before deduction of Royalty Burdens Payable) Light and Medium Natural Oil Crude Oil Heavy Oil NGLs Gas Equivalent mbbl mbbl mbbl bcf mboe ------------------------------------------------------------------------- Total Proved December 31, 2003 78,038 - 14,638 338.3 149,060 Exploration and Development 93 - 11 2.3 487 Improved Recovery 473 - 36 10.8 2,309 Revisions 1,168 - 771 7.1 3,124 Acquisitions 2,022 15,924 1,965 121.6 40,177 Dispositions - - - - - Production (7,619) (1,302) (1,933) (52.8) (19,655) ------------------------------------------------------------------------- December 31, 2004 74,175 14,622 15,488 427.3 175,501 ------------------------------------------------------------------------- Proved plus Probable December 31, 2003 97,360 - 18,250 412.8 184,416 Exploration and Development 173 - 17 3.2 724 Improved Recovery 367 - 37 12.0 2,404 Revisions 1,442 - 762 3.8 2,838 Acquisitions 2,343 19,547 2,262 142.4 47,886 Dispositions - - - - - Production (7,619) (1,302) (1,933) (52.8) (19,655) ------------------------------------------------------------------------- December 31, 2004 94,066 18,245 19,395 521.4 218,613 ------------------------------------------------------------------------- Net After Royalty Volumes Light and Medium Natural Oil Crude Oil Heavy Oil NGLs Gas Equivalent mbbl mbbl mbbl bcf mboe ------------------------------------------------------------------------- Total Proved December 31, 2003 66,667 - 10,509 271.1 122,357 Exploration and Development 79 - 8 1.8 394 Improved Recovery 405 - 25 8.6 1,869 Revisions 791 - 590 5.4 2,278 Acquisitions 1,733 13,863 1,392 97.1 33,179 Dispositions - - - - - Production (6,104) (1,130) (1,550) (42.7) (15,907) ------------------------------------------------------------------------- December 31, 2004 63,572 12,733 10,974 341.4 144,171 ------------------------------------------------------------------------- Proved plus Probable December 31, 2003 83,173 - 13,138 328.5 151,060 Exploration and Development 148 - 12 2.5 586 Improved Recovery 314 - 26 9.6 1,933 Revisions 908 - 581 4.1 2,173 Acquisitions 2,004 16,928 1,612 113.4 39,452 Dispositions - - - - - Production (6,104) (1,130) (1,550) (42.7) (15,907) ------------------------------------------------------------------------- December 31, 2003 80,443 15,798 13,819 415.4 179,298 ------------------------------------------------------------------------- Net Present Value (NPV) Summary 2004 ------------------------------------ At GLJ January 1, 2005 forecast prices and costs(x) Undiscounted Discounted Discounted Discounted Discounted $M at 8%, $M at 10%, $M at 12%, $M at 15%, $M ------------------------------------------------------------------------- Proved Producing 2,364,561 1,650,513 1,544,553 1,454,228 1,340,922 Proved Developed Non-Producing 109,632 66,740 60,905 56,019 49,999 Proved Undeveloped 458,079 240,947 208,768 181,768 148,767 ------------------------------------------------------------------------- Total Proved 2,932,271 1,958,199 1,814,226 1,692,016 1,539,687 ------------------------------------------------------------------------- Proved plus Probable 3,836,540 2,364,797 2,167,082 2,002,558 1,801,428 ------------------------------------------------------------------------- (x) Prior to provision for income taxes, interest, debt service charges and general and administrative expenses. Constant Prices at December 31, 2004(x) Undiscounted Discounted Discounted Discounted Discounted $M at 8%, $M at 10%, $M at 12%, $M at 15%, $M ------------------------------------------------------------------------- Proved Producing 2,720,359 1,805,738 1,674,719 1,564,163 1,427,068 Proved Developed Non-Producing 120,672 74,590 68,077 62,587 55,785 Proved Undeveloped 534,033 286,803 249,589 218,250 179,808 ------------------------------------------------------------------------- Total Proved 3,375,064 2,167,130 1,992,385 1,845,000 1,662,661 ------------------------------------------------------------------------- Proved plus Probable 4,345,327 2,613,047 2,379,906 2,186,164 1,949,936 ------------------------------------------------------------------------- (x) Prior to provision for income taxes, interest, debt service charges and general and administrative expenses. GLJ's price forecast is shown below: Edmonton WTI Light Natural Crude Oil Crude Oil Gas at AECO Year ($U.S./bbl) ($Cdn/bbl) ($Cdn/mmbtu) ------------------------------------------------------------------------- 2005 42.00 50.25 6.60 2006 40.00 47.25 6.35 2007 38.00 45.50 6.15 2008 36.00 43.25 6.00 2009 34.00 40.75 6.00 2010 33.00 39.50 6.00 2011 33.00 39.50 6.00 2012 33.00 39.50 6.00 2013 33.50 40.00 6.10 2014 34.00 40.75 6.20 2015 34.50 41.25 6.30 Escalate thereafter 2.0% per year 2.0% per year 2.0% per year Constant Prices at December 31, 2004: Edmonton WTI Light Natural Crude Oil Crude Oil Gas at AECO ($U.S./bbl) ($Cdn/bbl) ($Cdn/mmbtu) ------------------------------------------- 43.45 46.54 6.79 Net Asset Value (NAV) at December 31, 2004 In the following table, Pengrowth's net asset value is measured with reference to the present value of future net cash flows from reserves, as estimated by GLJ. The calculation is shown using both the GLJ forecast prices and constant (year-end 2004) prices. NAV at December 31, 2004 GLJ GLJ Forecast Constant $Thousands, except per unit amounts Prices Prices ------------------------------------------------------------------------- Value of Proved plus Probable Reserves discounted at 10% $ 2,167,082 $ 2,379,906 Undeveloped Lands(1) 35,326 35,326 Working Capital Deficit(2) (8,090) (8,090) Reclamation Fund 8,309 8,309 Long-term debt(3) (383,616) (383,616) Asset Retirement Obligation(4) (110,999) (89,725) ------------------------------------------------------------------------- Net Asset Value $ 1,708,012 $ 1,942,110 Units Outstanding (000's) 152,973 152,973 NAV/Unit $ 11.17 $ 12.70 ------------------------------------------------------------------------- (1) Pengrowth's internal estimate (2) Working capital excludes distributions payable (3) Long-term debt plus long-term portion of note payable and contract liabilities (4) The Asset Retirement Obligation (ARO) is based on the same methodology used to calculate the ARO on Pengrowth's year-end financial statements, except that the future expected ARO costs were inflated at 2% and discounted at 10% and well abandonment costs included in the GLJ report were deducted. Reserve Life Index (RLI) Pengrowth's proved RLI decreased from 8.9 years to 8.6 years and the proved plus probable RLI decreased to 10.4 years from 10.6 years in 2003. Reserve Life Index 2004 2003 2002 ------------------------------------------------------------------------- Total Proved 8.6 8.9 10.0 Proved plus Probable (Established reserves prior to 2003) 10.4 10.6 11.6 Development Activity During 2004, Pengrowth spent $161.1 million on development and optimization activities. The largest expenditures were in Judy Creek ($38.3 million), SOEP ($31.9 million), Monogram ($17.7 million), Weyburn ($5.4 million) and Squirrel ($5.3 million). Pengrowth does not typically participate in exploration activities and in 2004 most of the capital spent on development was directed towards arresting production declines and improving recovery by infill drilling, rather than finding new reserves. The following table provides further detail regarding Pengrowth's capital expenditures by major property for 2004. Capital expenditures for 2003 are also provided for purposes of comparison. Capital Expenditures Year Ended December 31 2004 2003 ------------------------------------------------------------------------- Total Total ($ millions) Development Capital Capital Property Drilling Facilities Expenditures Expenditures ------------------------------------------------------------------------- Judy Creek 35.2 3.1 38.3 21.5 SOEP 8.1 23.8 31.9 15.0 Monogram 12.4 5.3 17.7 0.1 Weyburn 3.5 1.9 5.4 8.7 Squirrel 4.8 0.5 5.3 0.4 Princess 4.2 0.3 4.5 - Dunvegan 3.3 0.7 4.0 1.5 McLeod River 4.4 0.1 4.5 6.0 Swan Hills 2.9 1.0 3.9 1.1 Bodo 3.3 - 3.3 - Oak 2.0 1.2 3.2 6.1 Weasel 2.6 0.3 2.9 0.2 Tilley 2.2 0.4 2.6 0.9 Laprise 2.4 0.1 2.5 1.3 Countess 0.2 2.2 2.4 - Tangleflags 1.9 0.5 2.4 - House Mountain 2.2 - 2.2 2.8 Tupper 1.1 0.9 2.0 1.8 Elm 1.5 0.1 1.6 2.4 Redeye 0.6 0.1 0.7 1.3 Cessford 0.1 0.2 0.3 7.2 Other 13.2 6.3 19.5 7.4 ------------------------------------------------------------------------- 112.1 49.0 161.1 85.7 ------------------------------------------------------------------------- In Judy Creek, development activity in 2004 was largely focused within the "A" Pool and included five horizontal solvent injection wells and five oil producers. Drilling and related activities such as well workovers and conversions resulted in the development of nine new solvent patterns and three new waterflood patterns in 2004. Six of the new solvent patterns were receiving solvent by year end with response expected during the first quarter of 2005. The remaining patterns are scheduled to begin injection by mid 2005 with response expected one to three months later. These and earlier such initiatives resulted in reclassifying 1.3 mmboe to proved producing reserves. During 2004, significant upgrades were also completed on the produced water injection system and the control systems of five compressor installations. These proactive upgrades improve the integrity and operating efficiency of the facilities and are expected to reduce maintenance costs and fuel consumption. Most of the 2004 SOEP capital expenditures were directed towards the development of the South Venture field and Thebaud compression. The South Venture platform and topsides were successfully installed in late 2004 with production from the first South Venture well (SV1) starting to flow to Thebaud on December 7, 2004. A second South Venture well (SV2) was spudded in 2004 but drilling was temporarily suspended during installation of the production platform. The SV2 well reached total depth in early 2005. Significant capital was also spent on the engineering and design of the compression facilities that will be installed at Thebaud in 2006. In addition to the engineering and design, purchase orders were placed for the 30,000 hp compression unit and the materials needed for the fabrication of the platform and topsides. These items are routinely ordered early to ensure they are available when required at the fabrication yard in Korea. In Monogram, a shallow gas infill drilling program was completed in 2004. In total 154 wells were drilled with 149 wells on stream by year-end. The infill program more than doubled Pengrowth's existing production of approximately 7.5 mmcf per day and resulted in 11.2 bcf of reserves being reclassified as proved producing. In Weyburn, the majority of the capital was directed towards expansion and optimization of the CO2 miscible flood. Twelve new miscible flood patterns were developed in 2004, adding to the 32 from previous years. In addition, there was ongoing development and optimization in existing enhanced oil recovery and waterflood areas where a total of 24 horizontal infill/re- entry wells were drilled. The success of the miscible flood and infill drilling program resulted in average production of 23,400 barrels of oil per day (bopd) during 2004 and an exit rate of 25,800 bopd, both exceeding budget expectations. In Squirrel capital spending was largely focused on optimizing the North Pine waterflood project to maximize oil recovery. During 2004, five wells were drilled into the pool and another was converted to injection. In addition, new reserves encountered in uphole secondary zones are being exploited. Acquisitions In 2004, Pengrowth made a major acquisition in Western Canada, purchasing oil and natural gas assets from a subsidiary of Murphy Oil Corporation. The acquisition added almost 14,600 boepd of production for a purchase price of $550.8 million and closed on May 31, 2004. The high quality, mostly operated properties offer numerous development opportunities and complement Pengrowth's existing property portfolio. Pengrowth also acquired an additional 34.35% working interest in the Pengrowth operated Kaybob Notikewin Gas Unit adding 1.8 mmboe of proved plus probable reserves. The acquisition closed on August 12, 2004 and brought Pengrowth's ownership in the Unit to 98.88%. The acquisition price was $20.0 million, before adjustments. Total Future Net Revenue (Undiscounted) GLJ January 1, 2005 forecast pricing: Royalties Operating Revenue $M $M Costs, $M ------------------------------------------------------------------------- Proved Producing 5,525,488 976,057 1,897,231 Proved Developed Non-Producing 184,689 37,581 28,417 Proved Undeveloped 1,252,211 185,301 409,293 ------------------------------------------------------------------------- Total Proved 6,962,388 1,198,939 2,334,942 ------------------------------------------------------------------------- Total Probable 1,836,049 329,329 535,287 ------------------------------------------------------------------------- Proved plus Probable 8,798,437 1,528,268 2,870,229 ------------------------------------------------------------------------- Future Net Revenue Capital Abandon- Before Development ment(x) Income Costs, $M Costs, $M Tax, $M ------------------------------------------------------------------------- Proved Producing 172,616 115,024 2,364,561 Proved Developed Non-Producing 6,603 2,455 109,632 Proved Undeveloped 193,240 6,299 458,079 ------------------------------------------------------------------------- Total Proved 372,458 123,778 2,932,271 ------------------------------------------------------------------------- Total Probable 55,590 11,574 904,268 ------------------------------------------------------------------------- Proved plus Probable 428,049 135,352 3,836,540 ------------------------------------------------------------------------- Constant Price at December 31, 2004: Royalties Operating Revenue $M $M Costs, $M ------------------------------------------------------------------------- Proved Producing 5,572,368 1,002,442 1,599,656 Proved Developed Non-Producing 192,926 40,514 23,440 Proved Undeveloped 1,286,956 211,288 355,910 ------------------------------------------------------------------------- Total Proved 7,052,250 1,254,243 1,979,007 ------------------------------------------------------------------------ Total Probable 1,717,629 329,584 363,928 ------------------------------------------------------------------------ Proved plus Probable 8,769,879 1,583,828 2,342,934 ------------------------------------------------------------------------ Future Net Revenue Capital Abandon- Before Development ment(x) Income Costs, $M Costs, $M Tax, $M ------------------------------------------------------------------------- Proved Producing 162,543 87,368 2,720,359 Proved Developed Non-Producing 6,311 1,988 120,672 Proved Undeveloped 182,348 3,377 534,033 ------------------------------------------------------------------------ Total Proved 351,202 92,733 3,375,064 ------------------------------------------------------------------------ Total Probable 51,386 2,469 970,262 ------------------------------------------------------------------------ Proved plus Probable 402,588 95,202 4,345,327 ------------------------------------------------------------------------ (x) Downhole abandonment costs The foregoing tables represent GLJ's estimates of future net revenue and do not represent fair market value. FINANCIAL UPDATE In 2004, Pengrowth continued its policy of issuing new equity when appropriate while maintaining a high distribution pay-out ratio to unitholders. During the year, Pengrowth raised a total of $509.8 million in new equity proceeds on a net basis, issuing a total of 29.1 million additional trust units. On March 23, 2004 Pengrowth completed a public offering of 10.9 million trust units at $18.40 per unit to raise total gross proceeds of $200.6 million, and net proceeds of $189.9 million and on December 30, 2004 Pengrowth completed a public offering of 16.0 million Class B trust units at $18.70 per trust unit to raise total gross proceeds of $298.9 million, and net proceeds of $283.3 million. During 2004, 0.9 million Class B trust units were issued under the DRIP at an average price of $17.84 per trust unit, raising additional equity of $16.4 million, and 1.3 million Class B trust units were issued under the employee trust unit option and rights plans, at an average price of $15.64 per trust unit, to raise an additional $20.3 million in new equity. As a result non-Canadian resident ownership of Pengrowth was reduced to 50.2% by year-end 2004. Financial Resources and Liquidity At year-end 2004, Pengrowth had a long-term debt-to-debt plus equity at book value ratio of 0.2 and maintained $375 million in committed credit facilities which were reduced by drawings of $106 million and by $23 million in letters of credit outstanding at year-end. In addition, Pengrowth maintains a $35 million demand operating line of credit. Pengrowth remains well positioned to fund its 2005 development program and to take advantage of acquisition opportunities as they arise. Long-term debt at December 31, 2004 included fixed rate term debt denominated in U.S. dollars and translated to Cdn $240.4 million. Due to the improvement in the Canadian to U.S. dollar exchange rate, an unrealized gain of Cdn $49.8 million has been recorded since the U.S. dollar denominated debt was issued in April of 2003. Pengrowth's long-term debt increased by $86.1 million in fiscal 2004 to $345.4 million at the end of 2004. At December 31, 2004 Pengrowth also had a $35 million non-interest bearing note payable to Emera Offshore Incorporated ("Emera") related to the purchase of the SOEP offshore facilities from Emera on December 31, 2003. The terms of this note are provided in Note 8 to the financial statements. During the year Pengrowth incurred $325 million of new debt to fund the acquisition of the Murphy Assets. Of this amount, $220 million was comprised of an acquisition bridge facility with a one year term ending May 31, 2005 with the remaining $105 million drawn from a revolving credit facility with a renewal date of May 30, 2005. A portion of the proceeds from the December 30, 2004 Class B trust unit offering was used to fully repay the drawing on the bridge facility. Financial Leverage and Coverage 2004 2003 ------------------------------------------------------------------------- Distributable cash to interest expense (times) 12 17 Long-term debt to Distributable cash (times) 1.0 0.8 Long-term debt-to-debt plus equity 19% 18% Interest Pengrowth's average long-term debt balances increased by approximately 58% in 2004 compared to 2003. As a result, interest expense increased by 65% to $29.9 million in 2004 ($9.3 million in the fourth quarter) from $18.2 million in 2003 ($3.8 million in the fourth quarter), reflecting a higher average debt level and higher standby fees and debt amortization costs. Standby fees related to the set-up of bridge financing utilized for the Murphy acquisition amounted to $3.9 million (2003 - nil). Interest expense also includes $0.3 million of fees related to the amortization of U.S. debt issue costs (2003 - $0.2 million). Imputed interest on the note payable to Emera was also recorded in the amount of $1.6 million (2003 - nil). The average interest rate on Pengrowth's long-term debt outstanding at December 31, 2004 is 4.59%. Approximately 70% of Pengrowth's outstanding debt at December 31, 2004 incurs interest expense payable in U.S. dollars and therefore remains subject to fluctuations in the exchange rate. The Note Payable is non-interest bearing. Foreign Currency Gains and Losses Pengrowth recorded a net foreign exchange gain of $17.3 million in 2004, compared to a net foreign exchange gain of $29.9 million in 2003. Included in the 2004 net gain of $17.3 million is an $18.9 million unrealized foreign exchange gain related to the U.S. dollar denominated debt. This gain arises as a result of the increase in the Canadian to U.S. dollar exchange rate in 2004 from a rate of approximately $0.77 at December 31, 2003 to a rate of approximately $0.83 at December 31, 2004. The balance, a foreign exchange loss of $1.6 million relates mainly to U.S. dollar denominated natural gas sales from SOEP. Pengrowth has hedged the exchange rate on a portion of these U.S. dollar denominated gas sales. Revenues are recorded at the average exchange rate for the production month in which they accrue, with payment being received on or about the 25th of the following month. As a result of the increase in the Canadian dollar relative to the U.S. dollar over the course of the year, a foreign exchange loss was recorded to the extent that there was a difference between the average exchange rate for the month of production and the exchange rate at the date the payments were received on that portion of production sales that remained unhedged. Pengrowth has arranged a significant portion of its long-term debt in U.S. dollars as a natural hedge against a stronger Canadian dollar, as the negative impact on oil and gas sales is somewhat offset by a reduction in the U.S. dollar denominated interest cost. Price Risk Management Pengrowth uses forward and futures contracts to manage its exposure to commodity price fluctuations. Commodity price hedges in place at December 31, 2004 are detailed in Note 17 to the Financial Statements. Pengrowth has not entered into any additional contracts subsequent to year end. General and Administrative General and administrative expenses ("G&A") increased to $24.4 million ($1.24 per boe) from $16.0 million ($0.89 per boe) in 2003, including $6.9 million in the fourth quarter of 2004 compared to $4.1 million in the same quarter of 2003. Included in 2004 G&A is $2.3 million (2003 - $0.2 million) in non-cash compensation expense related to trust unit options and rights (see Note 2 and Note 10 to the Financial Statements for details). Also included in 2004 G&A is $0.8 million for estimated reimbursement of G&A expenses incurred by the Manager, pursuant to the Management Agreement. Excluding the non-cash component of G&A, and the reimbursement of Manager expenses, 2004 year to date G&A increased by $5.5 million over 2003 levels. G&A costs increased due to a number of factors including the addition of personnel and office space in conjunction with the purchase of the Murphy Assets and costs incurred in conjunction with the restructuring of the Class A and Class B trust units. Other ongoing factors contributing to a general increase in G&A costs include increasing financial reporting, legal and regulatory costs from the growth in our unitholder base, and increasing regulatory requirements including preparing for compliance with Section 404 of the Sarbanes Oxley Act when it becomes applicable. Management Fees Management fees paid to Pengrowth Management Limited ("the Manager") increased to $12.9 million in 2004 from $10.2 million in 2003. The base fees paid to the manager totaled $6.8 million and are calculated as a fixed percentage of "net operating income" (oil and gas sales and other income, less royalties, operating costs, solvent amortization and reclamation funding). Although the fixed percentage rates at which base fees are calculated decreased by 46.5% from an average rate of 2.66% to 1.42% under the new Management Agreement effective July 1, 2003, there was an increase in total management fees due to the higher level of net operating income in 2004. Management fees for 2004 also include a performance fee of $6.1 million, which combined with the base fee for the period is equivalent to the cap of 80% of total fees that would have been earned by the Manager for that period pursuant to the old Management Agreement. The Manager earned the maximum performance fee by meeting or exceeding the performance criteria for a rolling three year average total return in excess of 8.0%. The Manager achieved a three year average return exceeding 25% as at the end of 2004. Related Party Transactions Details of related party transactions incurred in 2004 and 2003 are provided in Note 15 to the financial statements. These transactions include the Management fees paid to the Manager, as discussed in the preceding paragraphs. The Manager is controlled by James S. Kinnear, the Chairman, President and Chief Executive Officer of Pengrowth Corporation. As discussed above, the Management fees paid to the Manager are pursuant to a Management Agreement which has been approved by the trust unitholders. Mr. Kinnear is not entitled to receive any salary or bonus in his capacity as a director and officer of Pengrowth Corporation. Related party transactions in 2004 also include $841,457 (2003 - $675,692) paid to a firm controlled by the Corporate Secretary of Pengrowth Corporation, Charles V. Selby. These fees are paid in respect of legal and advisory services provided by the Corporate Secretary. Taxes In determining its taxable income, Pengrowth Corporation deducts royalty payments to unitholders, and historically, this has been sufficient to reduce taxable income to nil. As a result of Pengrowth's distribution approach, whereby approximately 10% of funds available for distribution are withheld to repay debt or fund future capital expenditures, the Corporation could become subject to taxation on a portion of its income within the Corporation at some point in the future. However the Corporation believes there are sufficient tax pools available in the Corporation at present to offset the expected level of income to be retained. Capital taxes of $4.6 million in 2004 (2003 - $1.8 million) include Federal Large Corporations Tax (LCT) of $1.3 million (2003 - $0.6 million) and Saskatchewan Capital Tax and Resource Surcharge of $3.2 million (2003 - $1.2 million). Distributions and Taxability of Distributions Pengrowth generated $363.1 million of Distributable cash related to 2004 cash flow, compared to $313.4 million in 2003. This equates to 90% of funds generated from operations, compared to 88% in 2003. Pengrowth currently withholds approximately 10% of cash available for distribution to repay debt and/or contribute to capital spending in the future. The Board of Directors may decide to increase (or decrease) the amount withheld in the future, depending on a number of factors, including future commodity prices, capital expenditure requirements, and the availability of debt and equity capital. Board discretion with respect to withholding is subject to a maximum withholding amount of 20% of gross revenues, as approved by unitholders at the 2003 Annual General Meeting. Cash distributions are paid to unitholders on the 15th day of the second month following the month of production. Pengrowth paid $2.59 per trust unit as cash distributions during the 2004 calendar year. For Canadian tax purposes 55.32% of these distributions or $1.4328 per trust unit is taxable income to unitholders for the 2004 tax year. The remaining 44.68% or $1.1572 per trust unit is a tax deferred return of capital which will reduce the unitholder's cost base of the trust unit for purposes of calculating a capital gain or loss upon ultimate disposition of the trust units. There is no standardized measure of Distributable cash and therefore Distributable cash, as reported by Pengrowth, may not be comparable to similar measures presented by other trusts. The following table provides a reconciliation of Distributable cash for fiscal years 2004 and 2003. 2004 2003 ------------------------------------------------------------------------- Funds generated from operations $ 402,994 $ 356,414 Change in deferred injectants 746 (9,504) Change in Remediation Trust Funds (917) (713) Amortization of deferred charges (1,893) (204) Gain (loss) on sale of marketable securities 248 (94) ------------------------------------------------------------------------- Distributable cash before withholding 401,178 345,899 Cash withheld (38,117) (32,484) ------------------------------------------------------------------------- Distributable cash 363,061 313,415 Less: Actual distributions paid or declared (363,001) (313,381) ------------------------------------------------------------------------- Balance to be distributed $ 60 $ 34 ------------------------------------------------------------------------- Actual distributions paid or declared per unit $ 2.630 $ 2.680 At December 31, 2004, the trust had unused tax deductions of $7.66 per trust unit (2003 - $10.27 per unit). At this time, Pengrowth anticipates that approximately 70 - 75% of 2005 distributions will be taxable; this estimate is subject to change depending on a number of factors including, but not limited to, the level of commodity prices, acquisitions, dispositions, and new equity offerings. Depletion and Depreciation Depletion and depreciation of property, plant and equipment and other assets is provided on the unit of production method based on total proved reserves. The provision for depletion and depreciation increased 33% in 2004 to $247.3 million from $185.3 million in 2003 due to a larger depletable asset base and a higher depletion rate (production as a percentage of total proved reserves). On a unit of production basis, depletion increased 22% to $12.58 per boe in 2004 from $10.35 per boe in 2003. The increase in the per boe depletion amount in 2004 reflects the acquisition of the Murphy properties. Ceiling Test Under Canadian GAAP, a ceiling test is applied to the carrying value of the property, plant and equipment and other assets. The carrying value is assessed to be recoverable when the sum of the undiscounted cash flows expected from the production of proved reserves, the lower of cost and market of unproved properties and the cost of major development projects exceeds the carrying value. When the carrying value is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying value of assets exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves, the lower of cost and market of unproved properties and the cost of major development projects. The cash flows are estimated using expected future product prices and costs and are discounted using a risk-free interest rate. There was a significant surplus in the ceiling test at year end 2004. Asset Retirement Obligations In 2003, the CICA issued Section 3110, "Asset Retirement Obligations" (ARO) which harmonizes Canadian GAAP requirements with the corresponding U.S. GAAP requirements under SFAS 143. Under these standards, the fair value of a liability for ARO must be recognized in the period in which it is incurred, and a corresponding asset retirement cost is to be added to the carrying amount of the related asset. The capitalized amount is depleted on the unit- of-production method based on proved reserves. The liability amount is increased each reporting period due to the passage of time and the amount of accretion is expensed to income in the period. Actual costs incurred upon the settlement of the ARO are charged against the ARO. The new Canadian standard was effective for fiscal years beginning on or after January 1, 2004 with earlier adoption encouraged. Pengrowth elected to adopt this standard in 2003. The total future ARO were estimated by management based on Pengrowth's working interest in wells and facilities, estimated costs to remediate, reclaim and abandon the wells and facilities and the estimated timing of the costs to be incurred in future periods. Pengrowth has estimated the net present value of its total ARO to be $172 million as at December 31, 2004 (2003 - $103 million), based on a total future liability of $551 million (2003 - $352 million). These costs are expected to be incurred over 50 years with the majority of the costs incurred between 2014 and 2037. Pengrowth's credit adjusted risk free rate of eight percent and an inflation rate of 1.5 percent were used to calculate the net present value of the ARO. Remediation Trust Funds and Remediation and Abandonment Expenses During 2004, Pengrowth contributed $1.5 million into trust funds established to fund certain abandonment and reclamation costs associated with Judy Creek, Swan Hills and SOEP. The balance in these remediation trust funds was $8.3 million at December 31, 2004. Pengrowth takes a proactive approach to managing our well abandonment and site restoration obligations. We have an on-going program to abandon wells and reclaim well and facility sites on the properties we operate. In 2004, Pengrowth spent $ 4.4 million on abandonment and reclamation (2003 - $3.2 million). Pengrowth expects to spend approximately $8.2 million per year, prior to inflation, over the next ten years on remediation and abandonment expenses at operated properties. Future Tax Liability As required by Canadian GAAP, Pengrowth recorded a future tax liability upon acquisition of the Murphy Assets. The tax liability arises due to the deficiency in tax pools of the Murphy Assets acquired offset in part by excess tax pools (compared to book value) from past acquisitions. The future tax liability represents the income taxes that would arise, based on the enacted income tax rates, if the operating company's assets and liabilities were disposed of or settled at book value. Because of the tax structure of the Trust, Pengrowth does not expect to pay cash income taxes in the operating companies in the foreseeable future. Goodwill In accordance with Canadian GAAP, Pengrowth was also required to record goodwill of $170.6 million upon acquisition of the Murphy Assets. The goodwill value was determined based on the excess of total consideration paid less the net value assigned to other identifiable assets and liabilities, including the future income tax liability. Details of the acquisition are provided in Note 5 of the financial statements. Commitments and Contractual Obligations 2004 Contractual Obligations ($ thousands) ------------------------------------------------------------------------- 2005 2006 2007 2008 ------------------------------------------------------------------------- Long-Term Debt(1) - - - - Interest Payments on Long-Term Debt(2) 12,176 12,176 12,176 12,176 Note Payable 15,000 20,000 - - Operating Leases Office Rent 1,235 469 - - Vehicle Leases 745 700 567 342 ------------------------------------------------------------------------- 1,980 1,169 567 342 Purchase Obligations Pipeline transportation 41,475 41,281 40,192 33,420 Capital expenditures 36,900 34,800 6,600 - CO2 purchases 5,976 5,236 4,418 4,254 ------------------------------------------------------------------------- 84,351 81,317 51,210 37,674 Remediation trust fund payments 250 250 250 250 ------------------------------------------------------------------------- 113,757 114,912 64,203 50,442 ------------------------------------------------------------------------- ($ thousands) 2009 thereafter Total ------------------------------------------------------------ Long-Term Debt(1) - 345,400 345,400 Interest Payments on Long-Term Debt(2) 12,176 13,632 74,512 Note Payable - - 35,000 Operating Leases Office Rent - - 1,704 Vehicle Leases 95 - 2,449 ------------------------------------------------------------ 95 - 4,153 Purchase Obligations Pipeline transportation 29,728 63,894 249,990 Capital expenditures - - 78,300 CO2 purchases 4,289 23,512 47,686 ------------------------------------------------------------ 34,017 87,407 375,976 Remediation trust fund payments 250 - 1,250 ------------------------------------------------------------ 46,538 446,439 836,292 ------------------------------------------------------------ (1) U.S. dollar denominated debt due as follows $150M on April 2010 & $50M on April 2013, translated at the Dec 31, 2004 foreign exchange rate of 1.2020 Cdn/U.S. (2) Interest Payments on U.S. denominated debt, calculated based on Dec 31, 2004 foreign exchange rate. SUBSEQUENT EVENTS On January 21, 2005, Pengrowth announced it had entered into an agreement to purchase an additional 12.5% working interest in Swan Hills Unit No. 1 for a purchase price of $90 million, before adjustments. The transaction, which is subject to Rights of First Refusal, is effective October 1, 2004 and is anticipated to close on February 28, 2005. The acquisition would increase Pengrowth's working interest in the Swan Hills Unit No. 1 to 22.7%. On February 17, 2005, Pengrowth announced an Arrangement Agreement (the "Arrangement") with Crispin Energy Inc. ("Crispin") under which Pengrowth will acquire all of the issued and outstanding shares of Crispin on the basis of 0.0725 Class B trust units of the Trust for each share held by Canadian resident shareholders of Crispin and 0.0512 Class A trust units of the Trust for each share held by non-Canadian resident shareholders of Crispin. The Arrangement will require the approval of 66 2/3 percent of the votes cast by shareholders and optionholders of Crispin voting as a single class, the approval of the majority of shareholders excluding certain management personnel and the approval of the Court of Queen's Bench of Alberta and certain regulatory agencies. Completion of the Arrangement is expected to close prior to the end of April 2005. OUTLOOK Unitholders of Pengrowth Energy Trust saw Pengrowth complete one of its largest acquisitions with the purchase of the Murphy Assets in May 2004. The Murphy Assets were funded through two equity issues allowing Pengrowth to continue to maintain a prudent and flexible financial structure. Pengrowth will strive to provide attractive long-term returns for unitholders. Our business objectives include: - Maintaining a balanced portfolio of oil and gas properties in our key focus areas; - Growing production and reserves through accretive acquisitions and low risk development drilling; - Farming out undeveloped land with higher risk exploration potential; - Continuing to optimize costs and maximize netbacks; - The selective disposition of oil and gas properties that do not meet our return objectives; - Operating our properties in a safe and prudent manner in order to protect our employees, the public, the environment and our investment; - Continuing to maintain a stable distribution policy while withholding a portion of Distributable cash to fund future capital programs. At this time, Pengrowth is forecasting average 2005 production of 55,000 to 57,000 boepd from our existing properties. This estimate incorporates anticipated production additions from the Swan Hills acquisition, scheduled to close on February 28, 2005, as well as our 2005 development program, offset by the impact of expected production declines from normal operations. The above estimate excludes the potential impact of any future acquisitions or divestitures, including the acquisition of Crispin. Total operating costs for 2005 are expected to increase to approximately $200 million. This increase is due to the addition of a full-year of operating expenses associated with the Murphy Assets, Pengrowth's increased working interest in Swan Hills Unit No. 1 and the prospective addition of operating expenses associated with the recently announced acquisition of Crispin. Assuming Pengrowth's average production at the end of 2005 results largely as forecast above, Pengrowth currently estimates 2005 per boe operating costs between $9.61 and $9.96 per boe and combined G&A and Management fees of approximately $1.81 per boe. Budgeted capital expenditures for 2005 total approximately $171.0 million for maintenance and development opportunities at existing properties. Approximately one half of the expected 2005 expenditures are planned for the SOEP and Judy Creek properties. The above estimate does not take into account any incremental expenditures which may be incurred in association with the recently announced acquisitions of Swan Hills and Crispin. Pengrowth currently anticipates a successful completion of the acquisition on or before April 30, 2005. ------------------------------------------------------------------------ ------------------------------------------------------------------------ CONFERENCE CALL Pengrowth will hold a conference call beginning at 11:00 A.M. Eastern Time (9:00 A.M. Mountain Time) on Tuesday, March 1, 2005 during which Management will review Pengrowth's 2004 fourth quarter and full year financial and operating results and respond to inquiries from the investment community. To participate callers may dial (800) 814-4941 or Toronto local (416) 640-4127. To ensure timely participation in the teleconference callers are encouraged to dial in 10-15 minutes prior to commencement of the call to register. A live audio webcast will be accessible through the Webcast and Multimedia Centre section of Pengrowth's website at http://www.pengrowth.com/. The webcast will be archived through May 30, 2005. A telephone replay will be available through to midnight Eastern Time on Thursday, March 3, 2005 by dialing (877) 289-8525 or Toronto local (416) 640-1917 and entering passcode number 21108177 followed by the pound key. ------------------------------------------------------------------------ ------------------------------------------------------------------------ PENGROWTH CORPORATION James S. Kinnear, President SUPPLEMENTAL INFORMATION Summary of Quarterly Results ---------------------------- The following table is a summary of Quarterly results for 2004 and 2003. As this table illustrates, production and Distributable cash were impacted positively by the acquisition of the Murphy Assets in the second quarter of 2004. This table also shows the relatively high commodity prices sustained throughout 2003 and 2004, which have had a positive impact on net income and Distributable cash. Production declines were offset by the acquisition of the Murphy Assets in the second quarter of 2004, positively impacting net income. However, in the fourth quarter of 2004, net income was negatively impacted by the recognition of $15.6 million of future income tax expense representing an increase in the future tax liability subsequent to the acquisition of the Murphy Assets. Summary of Quarterly Results 2004 ($ thousands) Q1 Q2 Q3 Q4 Total Oil and gas sales $ 165,880 $ 193,637 $ 222,848 $ 218,835 $ 801,200 Net income $ 38,652 $ 32,684 $ 51,271 $ 31,138 $ 153,745 Net income per unit $0.31 $0.24 $0.38 $0.23 $1.15 Net income per unit - diluted $0.31 $0.24 $0.38 $0.23 $1.15 Distributable cash $ 83,606 $ 89,119 $ 93,870 $ 96,466 $ 363,061 Actual distributions paid or declared per unit $0.63 $0.64 $0.67 $0.69 $2.63 Daily production (boe) 45,668 51,451 60,151 57,425 53,702 Total production mboe (6:1) 4,156 4,682 5,534 5,283 19,655 Average price per boe $ 39.91 $ 41.36 $ 40.27 $ 41.42 $ 40.76 Operating netback per boe $ 25.71 $ 25.71 $ 22.77 $ 24.31 $ 24.51 2003 Q1 Q2 Q3 Q4 Total Oil and gas sales $ 204,824 $ 169,238 $ 162,819 $ 154,139 $ 691,020 Net income $ 62,920 $ 54,214 $ 34,808 $ 37,355 $ 189,297 Net income per unit $0.57 $0.49 $0.29 $0.31 $1.63 Net income per unit - diluted $0.57 $0.48 $0.29 $0.30 $1.63 Distributable cash $ 97,221 $ 71,774 $ 72,951 $ 71,469 $ 313,415 Actual distributions paid or declared per unit $0.75 $0.67 $0.63 $0.63 $2.68 Daily production (boe) 50,827 48,839 48,850 47,653 49,033 Total production mboe (6:1) 4,574 4,444 4,494 4,384 17,896 Average price per boe $ 44.78 $ 38.08 $ 36.22 $ 35.16 $ 38.61 Operating netback per boe $ 26.50 $ 21.11 $ 20.54 $ 20.43 $ 22.17 Selected Annual Information Financial Results ($thousands) 2004 2003 2002 Oil and gas sales $ 801,200 $ 691,020 $ 482,301 Net income $ 153,745 $ 189,297 $ 56,955 Net income per unit $1.15 $1.63 $0.63 Distributable cash $ 363,061 $ 313,415 $ 194,458 Actual distributions paid or declared per unit $2.63 $2.68 $2.07 Total assets $ 2,276,534 $ 1,673,718 $ 1,552,651 Long-term financial liabilities(x) $ 383,616 $ 294,300 $ 316,501 Unitholders' equity $ 1,462,211 $ 1,159,433 $ 1,073,164 Number of units outstanding at year-end (thousands) 152,973 123,874 110,562 (x) Long-term debt plus long-term portion of note payable and contract liabilities. Class A and Class B Trust Unit Reclassification Generally speaking, the Income Tax Act (Canada) provides that a trust will permanently lose its mutual fund trust status if it is established or maintained primarily for the benefit of non-residents of Canada (which is generally interpreted to mean that the majority of unitholders must not be non- residents of Canada) (the "Benefit Test"), unless at all times after February 21, 1990, "all or substantially all" of the Trust's property consisted of property other than taxable Canadian property (the "TCP Exception"). The Federal Budget tabled by the Minister of Finance on March 23, 2004 proposed several changes to Subsection 132(7) of the Tax Act to the effect that the TCP Exception would generally no longer be available to royalty trusts after December 31, 2004. On April 22, 2004, Pengrowth Energy Trust sought and obtained the approval of its unitholders for the reclassification of its trust units as Class A trust units and Class B trust units (the "A/B Structure"). The purpose of the A/B Structure was to enable Pengrowth Energy Trust to satisfy the Benefit Test by providing a mechanism to ensure that the majority of trust units, distributions, votes and entitlements to the capital of Pengrowth Energy Trust would be held by residents of Canada. The A/B Structure was implemented by Pengrowth Energy Trust on July 27, 2004, but the ownership threshold has not yet been achieved. As of December 31, 2004, the outstanding Class A trust units of Pengrowth Energy Trust represented approximately 50.20% of the total outstanding trust units. The Trust Indenture of Pengrowth Energy Trust currently stipulates that an ownership threshold of a maximum of 49.75% represented by Class A trust units must be achieved by June 1, 2005. It is anticipated that the ownership threshold will be achieved prior to June 1, 2005 due to the issuance of Class B trust units under the Arrangement with Crispin and through the issuance of Class B trust units through the DRIP and employee trust unit option and rights incentive plans. 2004 2003 -------------------- Class A trust units 50.20% 0.00% Class B trust units 49.75% 0.00% Trust units prior to reclassification 0.056% 100.00% On November 26, 2004, Pengrowth Energy Trust received a customary form of comfort letter from the Department of Finance (Canada) (the "November Finance Letter") stating that the Department of Finance will recommend to the Minister of Finance that an amendment be made to the TCP Exception that would clarify Pengrowth Energy Trust's ability to rely upon that exception and would effectively remove any significant risk regarding the status of Pengrowth Energy Trust as a Mutual Fund Trust. The November Finance Letter is subject to acceptance of the recommendations therein by the Minister of Finance and Parliament, which Pengrowth Energy Trust believes is reasonable to assume will occur. On December 6, 2004, the Minister of Finance tabled a Notice of Ways and Means Motion in the House of Commons to implement measures proposed in the March 23, 2004 Federal Budget. However, the changes to the Mutual Fund Trust provisions proposed in the March 23, 2004 Federal Budget to remove the TCP Exception were not included. The Minister of Finance indicated that further discussions would be pursued with the private sector concerning the appropriate tax treatment of non-residents investing in resource property through mutual funds. Therefore, uncertainty remains as to whether or not the TCP Exception will be available to royalty trusts such as Pengrowth Energy Trust indefinitely. To the extent that Class A trust units in the future represent less than the ownership threshold of 49.75%, conversions of Class B trust units to Class A trust units will be permissible under the Trust Indenture. Pengrowth intends to implement a new form of reservation system in order to provide all unitholders with an equal and orderly opportunity to convert Class B trust units into Class A trust units. All registered and beneficial unitholders will have the opportunity to participate in the reservation system by providing an appropriate form to Computershare Trust Company of Canada ("Computershare"). Computershare will, at a specified time, select unitholders from within the reservation system using a random selection process that essentially provides an equal opportunity to all unitholders within the system. Each selection will entitle a unitholder to convert up to 1,000 Class B trust units into Class A trust units on a one for one basis. Unitholders will remain in the reservation system until they receive reservation numbers in respect of all of their Class B trust units within the system or until the reservation expires in accordance with its terms. It is anticipated that selections will occur monthly, but they may occur more or less frequently as determined by the Board of Directors of Pengrowth. At each periodic selection, the number of unitholders that will be selected will be determined by the number of Class B trust units that may be converted into Class A trust units without exceeding the ownership threshold. Further details regarding the reservation system, including certain income tax consequences of exercising the conversion option, will be provided sufficiently in advance of the first selection process so that all interested unitholders will have an equal opportunity to participate. Trust Unit Information Trust Unit Trading - after re-class(x) Volume Value ($ High Low Close (000s) millions) TSX - PGF.A (Cdn$) 2004 1st quarter 2nd quarter 3rd quarter $ 24.19 $ 19.10 $ 22.67 1,672 $ 35.5 4th quarter $ 26.33 $ 20.03 $ 24.93 2,607 $ 58.9 Year $ 26.33 $ 19.10 $ 24.93 4,279 $ 94.4 TSX - PGF.B (Cdn$) 2004 1st quarter 2nd quarter 3rd quarter $ 20.00 $ 18.03 $ 18.87 5,588 $ 105.6 4th quarter $ 20.04 $ 17.51 $ 18.50 16,007 $ 301.8 Year $ 20.04 $ 17.51 $ 18.50 21,595 $ 407.4 NYSE - PGH (U.S.$) 2004 1st quarter 2nd quarter 3rd quarter $ 18.94 $ 14.40 $ 17.93 21,200 $ 350.4 4th quarter $ 21.24 $ 15.85 $ 20.82 31,174 $ 574.7 Year $ 21.24 $ 14.40 $ 20.82 52,374 $ 925.1 Trust Unit Trading - after re-class(x) Volume Value ($ High Low Close (000s) millions) TSX -PGF.UN (Cdn$) 2004 1st quarter $ 21.25 $ 15.55 $ 17.98 30,620 $ 567.8 2nd quarter $ 19.15 $ 16.15 $ 18.67 18,145 $ 328.5 3rd quarter $ 19.75 $ 18.52 $ 19.42 3,554 $ 68.5 4th quarter Year $ 21.25 $ 15.55 $ 19.42 52,319 $ 964.8 2003 1st quarter $ 15.90 $ 13.39 $ 14.25 20,122 $ 297.6 2nd quarter $ 18.22 $ 13.95 $ 17.25 32,575 $ 519.0 3rd quarter $ 17.87 $ 16.20 $ 17.25 20,476 $ 349.5 4th quarter $ 22.22 $ 16.75 $ 21.25 24,220 $ 451.6 Year $ 22.22 $ 13.39 $ 21.25 97,393 $1,617.7 NYSE - PGH (U.S.$) 2004 1st quarter $ 16.60 $ 12.10 $ 13.70 36,899 $ 525.6 2nd quarter $ 14.24 $ 11.62 $ 13.98 22,194 $ 295.9 3rd quarter $ 14.95 $ 13.84 $ 14.64 5,797 $ 84.5 4th quarter Year $ 14.95 $ 11.62 $ 14.64 64,890 $ 906.0 2003 1st quarter $ 10.67 $ 9.07 $ 9.71 8,168 $ 80.8 2nd quarter 13.80 9.40 12.83 22,500 271.1 3rd quarter 13.13 11.55 12.81 18,614 230.2 4th quarter 17.00 12.50 16.40 24,721 340.8 Year $ 17.00 $ 9.07 $ 16.40 74,003 $ 922.9 (x) July 27, 2004, trust units were re-classified as Class A or Class B units. Class A trust units trade on the New York Stock Exchange (NYSE under PGH and on the Toronto Stock Exchange (TSX) under PGF.A. Class B trust units trade only on the TSX under PGF.B. PENGROWTH ENERGY TRUST UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2004 PENGROWTH ENERGY TRUST CONSOLIDATED BALANCE SHEETS AS AT DECEMBER 31 (Stated in thousands of dollars) 2004 2003 ------------ ------------ (unaudited) (audited) ASSETS CURRENT ASSETS Cash and term deposits $ - $ 64,154 Accounts receivable 104,228 65,570 Inventory 439 699 ------------ ------------ 104,667 130,423 REMEDIATION TRUST FUNDS (Note 4) 8,309 7,392 DEFERRED CHARGES (Note 11) 3,651 5,544 GOODWILL (Note 5) 170,619 - PROPERTY, PLANT AND EQUIPMENT AND OTHER ASSETS (Note 6) 1,989,288 1,530,359 ------------ ------------ $ 2,276,534 $ 1,673,718 ------------ ------------ ------------ ------------ LIABILITIES AND UNITHOLDERS' EQUITY CURRENT LIABILITIES Bank indebtedness $ 4,214 $ - Accounts payable and accrued liabilities 80,423 54,196 Distributions payable to unitholders 70,456 52,139 Due to Pengrowth Management Limited 7,325 1,122 Note payable (Note 8) 15,000 10,000 Current portion of contract liabilities (Note 5) 5,795 - ------------ ------------ 183,213 117,457 NOTE PAYABLE (Note 8) 20,000 35,000 CONTRACT LIABILITIES (Note 5) 18,216 - LONG-TERM DEBT (Note 9) 345,400 259,300 ASSET RETIREMENT OBLIGATIONS (Note 7) 171,866 102,528 FUTURE INCOME TAXES (Note 14) 75,628 - TRUST UNITHOLDERS' EQUITY Trust Unitholders' capital (Note 10) 2,383,284 1,872,924 Contributed surplus (Note 10) 1,923 189 Accumulated earnings 727,057 573,312 Accumulated distributable cash (1,650,053) (1,286,992) ------------ ------------ 1,462,211 1,159,433 ------------ ------------ COMMITMENTS (Note 18) SUBSEQUENT EVENTS (Note 19) $ 2,276,534 $ 1,673,718 ------------ ------------ ------------ ------------ See accompanying notes to the unaudited consolidated financial statements. PENGROWTH ENERGY TRUST CONSOLIDATED STATEMENTS OF INCOME AND ACCUMULATED EARNINGS YEARS ENDED DECEMBER 31 (Stated in thousands of dollars) 2004 2003 ------------ ------------ (unaudited) (audited) REVENUES Oil and gas sales $ 801,200 $ 691,020 Processing and other income 12,390 9,726 Crown royalties, net of incentives (133,952) (108,325) Freehold royalties and mineral taxes (11,848) (6,580) ------------ ------------ 667,790 585,841 Interest and other income 1,770 840 ------------ ------------ NET REVENUE 669,560 586,681 EXPENSES Operating 159,742 149,032 Transportation 8,274 8,225 Amortization of injectants for miscible floods 19,669 32,541 Interest 29,924 18,153 General and administrative 24,448 15,997 Management fee 12,874 10,181 Foreign exchange gain (Note 12) (17,300) (29,911) Depletion and depreciation 247,332 185,270 Accretion (Note 7) 10,642 6,039 ------------ ------------ 495,605 395,527 ------------ ------------ NET INCOME BEFORE TAXES 173,955 191,154 Income tax expense (Note 14) Capital 4,594 1,857 Future 15,616 - ------------ ------------ 20,210 1,857 NET INCOME $ 153,745 $ 189,297 Accumulated earnings, beginning of year 573,312 384,015 ------------ ------------ ACCUMULATED EARNINGS, END OF PERIOD $ 727,057 $ 573,312 ------------ ------------ ------------ ------------ NET INCOME PER UNIT (Note 16) Basic $1.153 $1.633 ------------ ------------ ------------ ------------ Diluted $1.147 $1.625 ------------ ------------ ------------ ------------ See accompanying notes to the unaudited consolidated financial statements. PENGROWTH ENERGY TRUST CONSOLIDATED STATEMENTS OF CASH FLOW YEARS ENDED DECEMBER 31 (Stated in thousands of dollars) 2004 2003 ------------ ------------ (unaudited) (audited) CASH PROVIDED BY (USED FOR): OPERATING Net income $ 153,745 $ 189,297 Depletion, depreciation and accretion 257,974 191,309 Future income taxes 15,616 - Contract liability amortization (4,164) - Amortization of injectants 19,669 32,541 Purchase of injectants (20,415) (23,037) Expenditures on remediation (4,440) (3,243) Unrealized foreign exchange gain (Note 12) (18,900) (30,940) Trust unit based compensation (Note 10) 2,264 189 Amortization of deferred charges (Note 11) 1,893 204 (Gain) loss on sale of marketable securities (248) 94 ------------ ------------ Funds generated from operations 402,994 356,414 Changes in non-cash operating working capital (Note 13) 1,173 (9,863) ------------ ------------ 404,167 346,551 ------------ ------------ FINANCING Distributions (344,744) (306,591) Change in long-term debt 105,000 (26,261) Note payable (Note 8) (10,000) 41,393 Proceeds from issue of trust units 509,830 210,198 ------------ ------------ 260,086 (81,261) ------------ ------------ INVESTING Expenditures on property acquisitions (572,980) (122,964) Expenditures on property, plant and equipment (161,141) (85,718) Proceeds on property dispositions - 2,835 Deferred Charges - (2,141) Change in Remediation Trust Fund (917) (713) Purchase of marketable securities (2,680) - Proceeds from sale of marketable securities 2,928 1,812 Change in non-cash investing working capital (Note 13) 2,169 (2,539) ------------ ------------ (732,621) (209,428) ------------ ------------ INCREASE (DECREASE) IN CASH AND TERM DEPOSITS (68,368) 55,862 CASH AND TERM DEPOSITS AT BEGINNING OF YEAR 64,154 8,292 CASH AND TERM DEPOSITS (BANK INDEBTEDNESS) AT END OF YEAR $ (4,214) $ 64,154 ------------ ------------ ------------ ------------ See accompanying notes to the unaudited consolidated financial statements. FIRST AND FINAL ADD TO FOLLOW DATASOURCE: Pengrowth Energy Trust; Pengrowth Corporation CONTACT: For further information about Pengrowth, please visit our website http://www.pengrowth.com/ or contact: Investor Relations, E-mail: , Telephone: (403) 233-0224, Toll Free: 1-800-223-4122, Facsimile: (403) 294-0051; Investor Relations, Toronto, Toll Free: 1-888-744-1111, Facsimile: (416) 362-8191

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