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Pengrowth Energy Trust Announces Third Quarter 2005 Results

Posted on: Friday, 4 November 2005, 00:00 CST

Pengrowth Corporation ("Pengrowth"), administrator of Pengrowth Energy Trust (TSX:PGF.A) (TSX:PGF.B) (NYSE:PGH), announced the interim unaudited operating and financial results for the three month and nine month periods ended September 30, 2005.

- During the third quarter of 2005, Pengrowth generated record distributable cash at $162 million versus $104 million in the third quarter of 2004, an increase of more than 55 percent. This is the third consecutive quarter of record distributable cash. Distributable cash for the first nine months of 2005 increased 43 percent to $424 million from $296 million in the comparable period of 2004 representing the highest level of distributable cash generated over any three consecutive quarters in Pengrowth's history.

- Distributions to unitholders in the quarter totaled $0.69 per trust unit representing a payout ratio of 69 percent of cash generated from operations. Pengrowth's year-to-date payout ratio decreased to approximately 77 percent of cash generated from operations, representing the lowest payout ratio for any nine month period on record. The decrease in payout ratio is mainly a result of higher commodity prices and production.

- Pengrowth is pleased to announce an increase in monthly distributions for the fourth quarter of 2005 from $0.23 to $0.25 per trust unit beginning with the December 15, 2005.

- Capital expenditures for the first nine months of 2005 of $115 million were fully funded with retained cash and proceeds from the exercise of trust unit rights and options. Pengrowth currently anticipates the full year 2005 capital program to total $185 million.

- During the third quarter, Pengrowth executed purchase and sale agreements with several parties for the sale of certain non-core Pengrowth properties with associated production estimated at 200 barrels of oil equivalent per day for gross proceeds of approximately $19 million. In addition, Pengrowth is working towards finalizing purchase and sale agreements with several parties for gross proceeds of $20 million and associated production estimated at 400 barrels of oil equivalent per day.

- At the end of the third quarter of 2005, Pengrowth was capitalized with 12 percent net debt (long-term debt less working capital) representing a net debt to annualized cash flow from operations of 0.8 times.

- The strategy of Pengrowth's board is to continue to seek long life reservoirs with large reserves in place particularly where Pengrowth can augment value through enhanced recovery techniques. In order to increase the efficiency of our operations and to add momentum to value enhancing activities, Pengrowth has actively sought and successfully retained senior operations management. Pengrowth is pleased to welcome Larry Strong, Vice President, Geosciences; Jim Causgrove, Vice President, Production and Operations; and Bill Christensen, Vice President, Strategic Planning and Reservoir Exploitation to the Pengrowth team.

Note regarding currency: All figures contained within this report are quoted in Canadian dollars unless otherwise indicated.

Summary of Financial and Operating Results Three Months ended September 30 % ($thousands, except per unit amounts) 2005 2004 Change INCOME STATEMENT Oil and gas sales $ 304,484 $ 226,514 34% Net income $ 100,243 $ 51,271 96% Net income per unit $ 0.63 $ 0.38 66% Cash generated from operations $ 158,976 $ 116,258 37% Cash generated from operations per unit $ 1.00 $ 0.86 16% Distributable cash(1) $ 162,009 $ 104,304 55% Distributable cash per unit(1) $ 1.02 $ 0.77 32% Distributions $ 109,853 $ 93,870 17% Distributions paid or declared per unit $ 0.69 $ 0.67 3% Weighted average number of units outstanding 158,789 135,906 17% BALANCE SHEET Working capital $ (77,528) $ (311,352) (75)% Property, plant and equipment and other assets $ 2,090,399 $1,985,737 5% Long-term debt $ 422,220 $ 355,320 19% Unitholders' equity $ 1,467,859 $1,235,575 19% Unitholders' equity per unit $ 9.22 $ 9.06 2% Number of units outstanding at period end 159,263 136,449 17% DAILY PRODUCTION Crude oil (barrels) 20,660 20,735 0% Heavy oil (barrels) 5,405 6,507 (17)% Natural gas (thousands of cubic feet) 164,288 166,618 (1)% Natural gas liquids (barrels) 5,448 5,139 6% Total production (boe) 58,894 60,151 (2)% TOTAL PRODUCTION (mboe) 5,418 5,534 (2)% PRODUCTION PROFILE Crude oil 35% 34% Heavy oil 9% 11% Natural gas 47% 46% Natural gas liquids 9% 9% AVERAGE REALIZED PRICES Crude oil (per barrel) $ 63.95 $ 45.15 42% Heavy oil (per barrel) $ 47.74 $ 37.96 26% Natural gas (per mcf) $ 8.57 $ 6.36 35% Natural gas liquids (per barrel) $ 57.75 $ 42.33 36% Average realized price per boe $ 56.07 $ 40.90 37% (1) See the section entitled "Non-GAAP Financial Measures" Nine Months ended September 30 % ($thousands, except per unit amounts) 2005 2004 Change INCOME STATEMENT Oil and gas sales $ 797,587 $ 592,569 35% Net income $ 209,663 122,607 71% Net income per unit $ 1.34 $ 0.93 44% Cash generated from operations $ 421,482 $ 310,880 36% Cash generated from operations per unit $ 2.70 $ 2.35 15% Distributable cash(1) $ 423,860 $ 296,220 43% Distributable cash per unit(1) $ 2.71 $ 2.24 21% Distributions $ 326,119 $ 266,595 22% Distributions paid or declared per unit $ 2.07 $ 1.94 7% Weighted average number of units outstanding 156,318 132,213 18% BALANCE SHEET Working capital $ (77,528)$ (311,352) (75)% Property, plant and equipment and other assets $ 2,090,399 $ 1,985,737 5% Long-term debt $ 422,220 $ 355,320 19% Unitholders' equity $ 1,467,859 $ 1,235,575 19% Unitholders' equity per unit $ 9.22 $ 9.06 2% Number of units outstanding at period end 159,263 136,449 17% DAILY PRODUCTION Crude oil (barrels) 20,670 21,051 (2)% Heavy oil (barrels) 5,695 2,799 103% Natural gas (thousands of cubic feet) 158,426 140,133 13% Natural gas liquids (barrels) 5,885 5,246 12% Total production (boe) 58,654 52,452 12% TOTAL PRODUCTION (mboe) 16,013 14,372 11% PRODUCTION PROFILE Crude oil 35% 40% Heavy oil 10% 5% Natural gas 45% 45% Natural gas liquids 10% 10% AVERAGE PRICES Crude oil (per barrel) $ 58.31 $ 42.71 37% Heavy oil (per barrel) $ 33.82 $ 36.25 (7)% Natural gas (per mcf) $ 7.61 $ 6.72 13% Natural gas liquids (per barrel) $ 52.59 $ 40.21 31% Average price per boe $ 49.66 $ 41.05 21% (1) See the section entitled "Non-GAAP Financial Measures" Summary of Trust Unit Trading Data (thousands, Three Months ended Nine Months ended except per September 30 September 30 unit amounts) 2005 2004 2005 2004 TRUST UNIT TRADING (Class A) PGH (NYSE) after unit re-class(1) High $ 25.75 U.S. $ 18.94 U.S. $ 25.75 U.S $ 18.94 U.S. Low $ 21.55 U.S. $ 14.40 U.S. $ 18.11 U.S $ 14.40 U.S. Close $ 25.42 U.S. $ 17.93 U.S. $ 25.42 U.S $ 17.93 U.S. Value $340,318 U.S. $350,374 U.S. $1,190,435 U.S $350,374 U.S. Volume (thousands of units) 14,502 21,200 55,276 21,200 PGF.A (TSX)(1) High $ 30.10 $ 24.19 $ 30.10 $ 24.19 Low $ 26.30 $ 19.10 $ 22.15 $ 19.10 Close $ 29.50 $ 22.67 $ 29.50 $ 22.67 Value $ 58,000 $ 35,524 $ 157,672 $ 35,524 Volume (thousands of units) 2,047 1,672 5,894 1,672 TRUST UNIT TRADING (Class B) PGF.B (TSX)(1) High $ 21.26 $ 20.00 $ 21.26 $ 20.00 Low $ 18.25 $ 18.03 $ 16.10 $ 18.03 Close $ 20.58 $ 18.87 $ 20.58 $ 18.87 Value $441,039 $105,650 $1,327,210 $105,650 Volume (thousands of units) 22,738 5,588 71,326 5,588 TRUST UNIT TRADING (before unit re-class) PGH (NYSE) before unit re-class(1) High $ 14.95 U.S. $ 14.95 U.S. Low $ 13.84 U.S. $ 11.62 U.S. Close $ 14.64 U.S. $ 14.64 U.S. Value $ 84,506 U.S. $905,950 U.S. Volume (thousands of units) 5,797 64,890 PGF.UN (TSX)(1) High $ 19.75 $ 21.25 Low $ 18.52 $ 15.55 Close $ 19.42 $ 19.42 Value $ 68,531 $964,766 Volume (thousands of units) 3,554 52,319 (1) July 27, 2004, all trust units were re-classified into Class A or Class B trust units. Class A trust units trade on the NYSE under PGH and on the TSX under PGF.A. Class B trust units trade only on the TSX under PGF.B.

Note Regarding Forward-Looking Statements

This 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, including the business risks discussed below, 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.

When converting natural gas to equivalent barrels of oil within this discussion, Pengrowth uses the international standard of 6 thousand cubic feet (mcf) to one barrel of oil equivalent (boe). Production volumes and revenues are reported on a gross basis (before royalties) in accordance with Canadian practice. All amounts are stated in Canadian dollars unless otherwise specified.

Non-GAAP Financial Measures

This discussion and analysis refers to certain financial measures that are not determined in accordance with Canadian Generally Accepted Accounting Principals (GAAP). These measures do not have standardized meanings and may not be comparable to similar measures presented by other trusts or corporations. Measures such as distributable cash, distributable cash per trust unit and operating netbacks do not have standardized meanings prescribed by GAAP. During the second quarter of 2005, Pengrowth's withholding practice and presentation of distributable cash changed. The impact of the new practice is discussed in the Distributions and Taxability of Distributions section of this report, while the remaining non-GAAP measures are determined by reference to our financial statements. We discuss these measures because we believe that they facilitate the understanding of the results of our operations and financial position.

Overview

For the third consecutive quarter, Pengrowth achieved record net income and cash generated from operations in the third quarter of 2005. Also during the third quarter, Pengrowth divested certain non-core oil and natural gas properties for proceeds of approximately $19 million.

Continued strength in commodity prices and additional production from the Swan Hills Unit No. 1 and Crispin Energy Inc. acquisitions, which closed on February 28, 2005 and April 29, 2005, respectively, had a favourable impact on 2005 third quarter results relative to the third quarter of 2004.

Net Income

Net income for the third quarter of 2005 was $100.2 million ($0.63 per trust unit) compared to $51.3 million ($0.38 per trust unit) for the third quarter of 2004. For the first nine months of 2005 Pengrowth recorded net income of $209.7 million ($1.34 per trust unit) compared to $122.6 million ($0.93 per trust unit) for the first nine months of 2004. The increase in net income for the third quarter of 2005 compared to the same period last year is due mainly to a 37 percent increase in average commodity prices.

Production

Production for the third quarter of 2005 decreased approximately two percent compared to the third quarter of 2004. Natural production declines more than offset the increased production associated with ongoing development activities, the increased working interest in Swan Hills Unit No. 1, the Crispin acquisition and an additional shipment of condensate from the Sable Offshore Energy Project (SOEP). Third quarter production increased approximately two percent versus the second quarter of 2005 largely as a result of increased gas production at SOEP and Judy Creek.

On a year-to-date basis, production for the nine months ended September 30, 2005 was 12 percent higher than the same period last year, primarily due to the Murphy, Swan Hills Unit No. 1 and Crispin acquisitions and the contributions from ongoing development activities.

Daily Production Three months ended Nine months ended Sept 30, Jun 30, Sept 30, Sept 30, Sept 30, 2005 2005 2004 2005 2004 --------------------------------------------------------------------- Light crude oil (bbls) 20,660 20,906 20,735 20,670 21,051 Heavy oil (bbls) 5,405 5,641 6,507 5,695 2,799 Natural gas (mcf) 164,288 153,423 166,618 158,426 140,133 Natural gas liquids (bbls) 5,448 5,870 5,139 5,885 5,246 --------------------------------------------------------------------- Total boe per day 58,894 57,988 60,151 58,654 52,452 --------------------------------------------------------------------- ---------------------------------------------------------------------

Third quarter 2005 light crude oil production volumes remained relatively flat versus both the second quarter of 2005 and the third quarter of 2004. The Swan Hills Unit No. 1 and Crispin acquisitions, in addition to development activities over the past year, combined to offset natural production declines.

Heavy oil production decreased 17 percent in the third quarter of 2005 compared to the same period in 2004 and approximately four percent from the second quarter of 2005. The decrease is due to natural production declines, particularly at Tangleflags and Bodo.

Natural gas production remained unchanged in the third quarter of 2005 compared to the third quarter of 2004. Incremental volumes from development activities, including the Monogram area, as well as the Crispin acquisition largely offset the impact of natural production declines. Natural gas production was up seven percent versus the second quarter of 2005 resulting from additional volumes from SOEP and Judy Creek.

Natural gas liquids (NGL) production increased by six percent in the third quarter of 2005 over the same quarter of 2004 while decreasing seven percent versus the second quarter of 2005. The fluctuation in NGL sales is due in part to the timing of condensate sales from SOEP.

Prices

Pengrowth's average commodity price per boe for the third quarter of 2005, after the impact of hedging, was 37 percent higher than the third quarter of 2004 and 17 percent higher than the second quarter of 2005.

Average realized prices Cdn$ Three months ended Nine months ended (after the Sept 30, Jun 30, Sept 30, Sept 30, Sept 30, impact of hedging) 2005 2005 2004 2005 2004 --------------------------------------------------------------------- Light crude oil (per bbl) $63.95 $56.44 $45.15 $58.31 $42.71 Heavy oil (per bbl) 47.74 30.32 37.96 33.82 36.25 Natural gas (per mcf) 8.57 7.34 6.36 7.61 6.72 Natural gas liquids (per bbl) 57.75 50.03 42.33 52.59 40.21 --------------------------------------------------------------------- Total per boe $56.07 $47.79 $40.90 $49.66 $41.05 --------------------------------------------------------------------- ---------------------------------------------------------------------

Pengrowth's average realized light crude oil price, net of hedging losses, increased 42 percent in the third quarter of 2005 and 37 percent for the first nine months compared to the same periods of 2004. The West Texas Intermediate (WTI) benchmark price increased 44 percent in the third quarter of 2005 compared to the same period last year. This was partially offset by the appreciation in the Canadian dollar relative to the U.S. dollar. Pengrowth's average realized light crude oil price for the third quarter of 2005, net of hedging losses, increased 13 percent compared to the second quarter of 2005.

Pengrowth's average realized heavy oil price increased 26 percent in the third quarter of 2005 compared with the third quarter of 2004 and 57 percent versus the second quarter of 2005. The year-to-date average realized heavy oil price for the first nine months of 2005 compared to the same period of 2004 decreased seven percent largely as a result of widening in the light/heavy price differential and the increasing cost of diluent used to process the oil for transport.

Pengrowth's average realized natural gas price, net of hedging losses, for the third quarter of 2005 increased 35 percent to $8.57 per mcf compared to $6.36 per mcf over the same period last year, while also increasing 17 percent versus the second quarter of 2005 price of $7.34 per mcf. Pengrowth's average natural gas price increased year over year by 13 percent to $7.61 per mcf. By comparison on a year to date basis, the NYMEX last day average price increased by 23 percent while the AECO monthly spot price increased 11 percent. Certain fixed price gas contracts which were associated with the Murphy acquisition also partially offset the increase in market prices.

Price Risk Management Program

Pengrowth uses forward price swap and option contracts to manage its exposure to commodity price fluctuations, to provide a measure of stability to our monthly cash distributions and to partially secure returns on new acquisitions. On a combined basis, oil and gas hedging losses were $21.6 million ($3.99 per boe) for the third quarter and $38.1 million ($2.38 per boe) for the first nine months of 2005 compared to $18.9 million ($3.42 per boe) and $46.4 million ($3.23 per boe) for the respective periods of 2004.

With the continued strength in crude oil prices in the third quarter, Pengrowth realized a net hedging loss of $19.8 million ($10.42 per bbl) on crude oil price swap transactions, compared to a loss of $17.9 million ($9.38 per bbl) in the third quarter of 2004. On a year-to-date basis, Pengrowth has realized a net hedging loss of $37.4 million ($6.63 per bbl) for the first nine months of 2005 on crude oil price swap transactions, compared to a net hedging loss of $37.8 million ($6.55 per bbl) for the first nine months of 2004.

In the third quarter of 2005, Pengrowth realized a net hedging loss of $1.8 million ($0.12 per mcf) related to natural gas financial swap contracts, compared to a net hedging loss of $1.0 million ($0.07 per mcf) for the same period last year. On a year-to-date basis, Pengrowth has realized a net hedging loss of $0.7 million ($0.02 per mcf) in the first nine months of 2005 related to natural gas financial swap contracts, compared to a net hedging loss of $8.6 million ($0.22 per mcf) for the same period of last year.

In conjunction with the Murphy acquisition on May 31, 2004, Pengrowth assumed certain fixed price natural gas sales contracts associated with the Murphy reserves. Under these contracts, Pengrowth is obligated to sell 3,886 mmbtu per day, until April 30, 2009 at an average contract price of Cdn $2.27 per mmbtu. As required by GAAP, the fair value of the contract was recognized as a liability based on the mark-to-market value at May 31, 2004. The liability at September 30, 2005 of $19.7 million will continue to be drawn down and recognized in income as the contract is settled. As this is a non-cash component of income, it is not included in the calculation of distributable cash. At September 30, 2005, the mark-to-market value of Pengrowth's fixed price physical sales contract represented a potential loss of $37.8 million.

In addition, the following table lists the hedging contracts Pengrowth has in place at September 30, 2005.

Crude Oil Volume Reference Price Remaining Term (bbl per day) Point per bbl --------------------------------------------------------------------- 2005 - Financial Oct 1, 2005 - Dec 31, 2005 10,000 WTI (1) $54.39 Cdn 2006 - Financial Jan 1, 2006 - Dec 31, 2006 4,000 WTI (1) $64.08 Cdn Natural Gas Volume Reference Price Remaining Term (mmbtu per day) Point per mmbtu --------------------------------------------------------------------- 2005 - Financial Oct 1, 2005 - Dec 31, 2005 11,000 Tetco M3 (1) $ 9.27 Cdn Oct 1, 2005 - Dec 31, 2005 5,000 Transco Z6 (1) $10.11 Cdn Oct 1, 2005 - Dec 31, 2005 2,500 NGI Chicago (1) $ 9.41 Cdn Oct 1, 2005 - Dec 31, 2005 2,500 Nymex (1) $14.07 Cdn Oct 1, 2005 - Dec 31, 2005 2,370 AECO $ 8.35 Cdn 2006 - Financial Jan 1, 2006 - Dec 31, 2006 2,500 Transco Z6 (1) $10.63 Cdn Jan 1, 2006 - Dec 31, 2006 2,370 AECO $ 8.03 Cdn Jan 1, 2006 - Mar 31, 2006 2,500 Nymex (1) $14.56 Cdn (1) Associated Cdn$/US$ foreign exchange rate has been fixed.

At September 30, 2005, the mark-to-market value of Pengrowth's commodity hedges represented a potential loss of $64.2 million which consisted of a loss of $25.0 million on natural gas contracts and $39.2 million for crude oil contracts.

Royalties

Royalties, including crown, freehold and overriding royalties, were 19 percent of oil and gas sales in the third quarter of 2005, compared to 22 percent in the third quarter of 2004 and 19 percent in the second quarter of 2005. The decrease in royalty rate from the third quarter of 2004 to the third quarter of 2005 is primarily due to the non-recurring nature of a $4.4 million adjustment for Judy Creek royalties that was included in the third quarter of 2004. For the first nine months, royalties were 18 percent and 19 percent in 2005 and 2004, respectively.

Operating Costs

Operating costs were $57.4 million ($10.59 per boe) for the third quarter of 2005, compared to $47.2 million ($8.53 per boe) for the third quarter of 2004 and $50.4 million ($9.56 per boe) for the second quarter of 2005. For the nine months ended September 30, 2005, operating costs were $156.9 million ($9.80 per boe) compared to $117.1 million ($8.15 per boe) for the same period of 2004. The Murphy, Swan Hills Unit No. 1 and Crispin acquisitions, higher utility and oilfield services costs and the expense associated with the trust unit award plan contributed to higher operating costs in total as well as on a per boe basis compared to the third quarter of 2004 and the second quarter of 2005.

Heavy oil operating costs in 2005 have been impacted by a $2.1 million adjustment related to a prior period expense on a non-operated property and higher costs associated with rising natural gas costs at thermal recovery operations.

Injectants for Miscible Floods

During the third quarter of 2005, Pengrowth purchased and capitalized $6.9 million of injectants and amortized $6.0 million against third quarter net income and distributable cash, compared to $3.0 million and $4.7 million, respectively, in the third quarter of 2004 and $5.7 million and $6.0 million in the second quarter of 2005. On a year-to-date basis, Pengrowth has purchased and capitalized $20.2 million of injectants and amortized $17.3 million, compared to $12.2 million and $14.7 million, respectively, in the same period last year. The increase in injectant costs year over year is due mainly to Pengrowth's increased working interest at Swan Hills Unit No. 1. The majority of ethane and natural gas volumes injected at Judy Creek are proprietary volumes produced from Judy Creek and the Swan Hills area. Revenue is not recorded for volumes that are produced and subsequently re-injected.

At September 30, 2005, the balance of unamortized injectant costs was $27.9 million.

Operating 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 oil, heavy oil, natural gas and natural gas liquids production.

Operating netbacks during the quarter increased by approximately 49 percent reflecting the overall increase in oil and gas prices, net of hedging, offset partially by the increase in operating costs per boe.

-------------------- ------------------- Three months ended Nine months ended Combined Netbacks Sept 30, Sept 30, Sept 30, Sept 30, ($ per boe) 2005 2004 2005 2004 -------------------- ------------------- Sales price $ 56.07 $ 40.90 $ 49.66 $ 41.05 Other production income 0.13 0.02 0.15 0.18 -------------------- ------------------- 56.20 40.92 49.81 41.23 Processing and other income 0.39 0.53 0.86 0.70 Royalties (10.60) (8.88) (9.11) (7.73) Operating costs (10.59) (8.51) (9.80) (8.18) Transportation costs (0.36) (0.44) (0.35) (0.40) Amortization of injectants (1.10) (0.85) (1.08) (1.02) -------------------- ------------------- Operating netback $ 33.94 $ 22.77 $ 30.33 $ 24.60 -------------------- ------------------- -------------------- ------------------- -------------------- ------------------- Three months ended Nine months ended Light Crude Netbacks Sept 30, Sept 30, Sept 30, Sept 30, ($ per bbl) 2005 2004 2005 2004 -------------------- ------------------- Sales price $ 63.95 $ 45.15 $ 58.31 $ 42.71 Other production income 0.37 0.06 0.44 0.44 -------------------- ------------------- 64.32 45.21 58.75 43.15 Processing and other income 0.64 0.25 0.51 0.45 Royalties (11.03) (10.29) (9.39) (6.96) Operating costs (12.85) (9.38) (11.58) (9.34) Transportation costs (0.29) (0.23) (0.30) (0.23) Amortization of injectants (3.14) (2.46) (3.07) (2.55) -------------------- ------------------- Operating netback $ 37.65 $ 23.10 $ 34.92 $ 24.52 -------------------- ------------------- -------------------- ------------------- -------------------- ------------------- Three months ended Nine months ended Heavy Oil Netbacks Sept 30, Sept 30, Sept 30, Sept 30, ($ per bbl) 2005 2004 2005 2004 -------------------- ------------------- Sales price $ 47.74 $ 37.96 $ 33.82 $ 36.25 Processing and other income (0.83) - 0.24 - Royalties (8.00) (5.55) (5.03) (5.35) Operating costs (16.30) (11.20) (16.95) (10.14) -------------------- ------------------- Operating netback $ 22.61 $ 21.21 $ 12.08 $ 20.76 -------------------- ------------------- -------------------- ------------------- -------------------- ------------------- Three months ended Nine months ended Natural Gas Netbacks Sept 30, Sept 30, Sept 30, Sept 30, ($ per mcf) 2005 2004 2005 2004 -------------------- ------------------- Sales price $ 8.57 $ 6.36 $ 7.61 $ 6.72 Processing and other income 0.09 0.16 0.24 0.19 Royalties (1.47) (1.27) (1.36) (1.22) Operating costs (1.31) (1.22) (1.19) (1.15) Transportation costs (0.09) (0.13) (0.09) (0.11) -------------------- ------------------- Operating netback $ 5.79 $ 3.90 $ 5.21 $ 4.43 -------------------- ------------------- -------------------- ------------------- -------------------- ------------------- Three months ended Nine months ended NGL Netbacks Sept 30, Sept 30, Sept 30, Sept 30, ($ per bbl) 2005 2004 2005 2004 -------------------- ------------------- Sales price $ 57.75 $ 42.33 $ 52.59 $ 40.21 Royalties (20.57) (14.19) (16.27) (14.07) Operating costs (10.13) (8.07) (8.65) (7.95) Transportation costs - (0.10) - (0.10) -------------------- ------------------- Operating netback $ 27.05 $ 19.97 $ 27.67 $ 18.09 -------------------- ------------------- -------------------- -------------------

General and Administrative

General and administrative expenses (G&A) were $7.6 million ($1.40 per boe) in the third quarter of 2005 compared to $6.1 million ($1.11 per boe) for the third quarter of 2004. For the first nine months of 2005, G&A was $21.8 million ($1.36 per boe) compared to $17.5 million ($1.22 per boe) for the same period last year. Included in the third quarter of 2005 G&A is $0.6 million of non-cash compensation costs related to trust unit rights and deferred entitlement trust units (see note 1 to consolidated financial statements) compared to $0.6 million for the third quarter of 2004. The year-to-date non-cash component is $2.1 million compared to $1.9 million for the first nine months of 2004. Excluding the non-cash component of G&A, 2005 year-to-date G&A has increased over 2004 levels by $4.1 million mainly due to the addition of personnel and office space required to manage the Murphy assets as well as the expense associated with the trust unit award plan.

Management Fees

Management fees were $3.5 million ($0.65 per boe) for the third quarter of 2005 compared to $2.5 million ($0.45 per boe) for the third quarter of 2004. For the first nine months of 2005, management fees were $11.6 million ($0.72 per boe) for 2005 compared to $10.3 million ($0.72 per boe) for the same period in 2004.

Management fees recorded in the third quarter of 2005 include an accrual for estimated performance fees of $1.9 million. Under the current management agreement, which came into effect July 1, 2003, the manager will earn a performance fee if Pengrowth trust unit total returns exceed eight percent per annum on a three year rolling average basis. The maximum fees payable, including the performance fee, is limited to 80 percent of the fees that would otherwise have been payable under the previous management agreement for the first three years and 60 percent for the subsequent three years. Management fees have increased from 2004 mainly due to higher commodity prices that have increased cash generated from operations.

Interest

Interest expense decreased to $5.6 million in the third quarter of 2005 compared to $8.7 million for the third quarter of 2004 primarily due to reduced debt level. For the first nine months of 2005, interest expense was $16.8 million compared to $20.6 million for the same period of 2004. Interest expense includes $1.2 million of fees on a year-to-date basis related to the amortization of U.S. debt issue costs and imputed interest on the note payable to Emera Offshore Incorporated.

Depletion and Depreciation

Depletion and depreciation costs increased to $73.5 million in the third quarter of 2005 compared to $69.3 million in the third quarter of 2004. For the first nine months of 2005, depletion and depreciation costs were $213.6 million compared to $177.9 million in the first nine months of 2004. On a per boe basis, depletion and depreciation costs have increased to $13.57 per boe in the third quarter of 2005 compared to $12.53 per boe in the third quarter of 2004, and $13.34 per boe on a year-to-date basis, compared to $12.38 per boe in the first nine months of 2004. The increase is mainly attributable to recent purchases, including the Murphy acquisition in May 2004. With the sustained strength in commodity prices in recent years, the higher cost of acquiring oil and gas properties has increased the depletion rate per boe produced.

Distributions and Taxability of Distributions

Pengrowth generated $162.0 million ($1.02 per average trust unit outstanding) of distributable cash related to third quarter 2005 operations, compared to $104.3 million ($0.77 per average trust unit outstanding) in the third quarter of 2004. For the first nine months of 2005, Pengrowth generated $423.9 million distributable cash compared to $296.2 million in the first nine months of 2004. Distributions were $326.1 million for 2005 (2004 - $266.6 million) and as a percentage of cash generated from operations (payout ratio) represent approximately 77 percent (2004 - 86 percent). Pengrowth's previous practice had been to withhold approximately 10 percent of cash available for distribution to repay debt and/or contribute to capital spending. For the third quarter of 2005, the Board of Directors resolved to maintain the existing level of distributions at $0.23 per trust unit. Given the level of current commodity prices, this action has resulted in an increase in cash available to help fund Pengrowth's capital expenditures. Pengrowth is pleased to announce an increase in monthly distributions to $0.25 per trust unit for the fourth quarter of 2005 beginning with the December 15, 2005 distribution.

Cash distributions are paid to unitholders on the 15th day of the second month following the month of production. Pengrowth paid $0.69 per trust unit as cash distributions during the third quarter of 2005.

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. In conjunction with the change to Pengrowth's withholding practice, distributable cash as presented below may not be comparable to previous disclosures. The following table provides a reconciliation of distributable cash for the three and nine month periods ended September 30, 2005 and 2004.

($thousands, except Three months Nine months per unit amounts) ended Sept 30 ended Sept 30 ---------------------------------------------------------------------- -- 2005 2004 2005 2004 ---------------------------------------------------------------------- -- Cash generated from operations 158,976 116,258 421,482 310,880 Change in non-cash operating working capital (789) (9,857) (1,840) (9,749) Change in deferred injectants 892 (1,663) 2,854 (2,482) Change in remediation trust funds (272) (276) (803) (949) Change in deferred charges 2,818 (473) 2,028 (1,420) Other 384 315 139 (60) ---------------------------------------------------------------------- -- Distributable cash 162,009 104,304 423,860 296,220 ---------------------------------------------------------------------- -- ---------------------------------------------------------------------- -- Allocation of Distributable Cash Cash withheld 52,156 10,434 97,741 29,625 Distributions paid or declared 109,853 93,870 326,119 266,595 ---------------------------------------------------------------------- -- Distributable cash 162,009 104,304 423,860 296,220 ---------------------------------------------------------------------- -- Distributable cash per unit 1.02 0.77 2.71 2.24 Distributions paid or declared per unit 0.69 0.67 2.07 1.94 Payout ratio 69% 81% 77% 86% ---------------------------------------------------------------------- -- ---------------------------------------------------------------------- --

At this time, Pengrowth anticipates that approximately 75 to 80 percent of 2005 distributions will be taxable for Canadian residents; 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.

Liquidity and Capital Resources

Pengrowth's long-term debt at September 30, 2005 was $422.2 million, compared to $345.4 million at December 31, 2004 and $355.3 million at September 30, 2004. During the third quarter, Pengrowth received $18.6 million of proceeds from the sale of non-operated oil and natural gas properties. Year-to-date capital expenditures, excluding acquisitions, of $114.5 million were financed through the combination of cash withheld of $97.7 million and of $32.0 million proceeds from the exercise of trust unit rights and options.

Approximately $295 million of a $470 million revolving credit facility and a $35 million demand operating line of credit remain unutilized at September 30, 2005. The remainder of Pengrowth's debt outstanding at the end of the third quarter 2005 is U.S. dollar denominated fixed rate term debt, details of which are provided in Note 2 to the financial statements. Due to the change in the value of the U.S. dollar relative to the Canadian dollar, an unrealized gain of $12.9 million has been recorded in the quarter ended September 30, 2005 ($8.2 million year-to-date) on the U.S. dollar denominated debt. Since the U.S. $200 million denominated debt was issued in April 2003, the Canadian dollar has strengthened significantly, resulting in a cumulative unrealized gain of $58.0 million.

At the end of the third quarter of 2005, Pengrowth was capitalized with 12 percent net debt (long-term debt less working capital) and 88 percent equity, as compared with 20 percent debt and 80 percent equity at the end of the third quarter of 2004 (based on quarter-end market capitalization). The Trust's net debt to annualized cash flow from operations was approximately 0.8 times at the end of the third quarter of 2005, as compared to 1.7 times at the end of the third quarter of 2004.

As of November 2, 2005, the number of trust units outstanding was approximately: (000's) --------------------------------------------------- Class A trust units 77,524 Class B trust units 81,817 Undeclared trust units 43 --------------------------------------------------- Total 159,384 As of November 2, 2005, the number of trust unit options, rights and deferred entitlement trust units was approximately: (000's) --------------------------------------------------- Trust unit options 357 Rights incentive options 1,554 Deferred entitlement trust units 150 ---------------------------------------------------

Acquisitions and Dispositions

During the third quarter of 2005, Pengrowth received approximately $19 million of proceeds from the sale of non-core oil and natural gas properties with associated production of approximately 200 boe per day. Due to the timing of the sales, production from these properties is included in the third quarter of 2005 results.

Prior to the third quarter, Pengrowth successfully completed the acquisition of an additional 11.89 percent working interest in the Swan Hills Unit No. 1 property for $87 million which was funded through additional debt. Pengrowth also closed the acquisition of all of the issued and outstanding shares of Crispin Energy Inc. on April 29, 2005 by issuing approximately 677,000 Class A trust units and approximately 3,552,000 Class B trust units, valued at $88 million, and assuming debt of approximately $20 million.

Capital Spending

Capital expenditures for the nine months ending September 30, 2005 totaled $114.5 million including $24.6 million at Judy Creek, $18.5 million at SOEP, $7.8 million at Buick, $5.5 million at Swan Hills Unit No. 1, $4.9 million at Weyburn, and $4.5 million at Squirrel.

Pengrowth currently expects to spend a total of approximately $70 million on development activities in the remaining quarter of 2005 for a total revised capital program of approximately $185 million for full year 2005. The revised capital plan represents a decrease of $30 million or 14 percent from the previous guidance of $215 million. The reduction in the 2005 capital program reflects the impact of limited rig availability and weather related delays in planned development activities which have resulted in deferral of related expenditures to the 2006 capital year. This includes development activity planned at Pengrowth's operated Judy Creek and in Northeast British Columbia properties, as well as additional development drilling and facilities at the non-operated SOEP, Swan Hills Unit No. 1, Quirk Creek and Weyburn properties. Capital expenditures year-to-date have been fully funded from retained cash and proceeds from trust unit rights and options exercised.

Summary of Quarterly Results

The following table is a summary of quarterly results for 2003, 2004 and the first three quarters of 2005. Net income and net income per trust unit for the third quarter of 2005 increased over the second quarter of 2005, mainly due to a 19 percent increase in average per boe price realized as well as a $16 million change in unrealized foreign exchange gain partly offset by increased utility costs and the expense associated with the trust unit award plan.

2005 --------------------------------------------------------------------- Q1 Q2 Q3 --------------------------------------------------------------------- Oil and gas sales ($000's) 239,913 253,189 304,484 Net income ($000's) 56,314 53,106 100,243 Net income per unit ($) 0.37 0.34 0.63 Net income per unit - diluted ($) 0.37 0.34 0.63 Distributable cash ($000's) 127,804 134,047 162,009 Actual distributions paid or declared per unit ($) 0.69 0.69 0.69 Daily production (boe) 59,082 57,988 58,894 Total production (mboe) 5,317 5,277 5,418 Average realized price per boe ($ per boe) 44.97 47.79 56.07 Operating netback per boe ($ per boe) 27.70 29.26 33.94 2004 --------------------------------------------------------------------- Q1 Q2 Q3 Q4 --------------------------------------------------------------------- Oil and gas sales ($000's) 168,771 197,284 226,514 223,183 Net income ($000's) 38,652 32,684 51,271 31,138 Net income per unit ($) 0.31 0.24 0.38 0.23 Net income per unit - diluted ($) 0.31 0.24 0.38 0.23 Distributable cash ($000's) 92,895 99,021 104,304 104,598 Actual distributions paid or declared per unit ($) 0.63 0.64 0.67 0.69 Daily production (boe) 45,668 51,451 60,151 57,425 Total production (mboe) 4,156 4,682 5,534 5,283 Average realized price per boe ($ per boe) 40.37 41.83 40.90 42.08 Operating netback per boe ($ per boe) 25.71 25.71 22.77 24.31 2003 --------------------------------------------------------------------- Q1 Q2 Q3 Q4 --------------------------------------------------------------------- Oil and gas sales ($000's) 207,891 171,836 165,601 157,404 Net income ($000's) 62,920 54,214 34,808 37,355 Net income per unit ($) 0.57 0.49 0.29 0.31 Net income per unit - diluted ($) 0.57 0.48 0.29 0.30 Distributable cash ($000's) 108,025 79,695 81,057 77,122 Actual distributions paid or declared per unit ($) 0.75 0.67 0.63 0.63 Daily production (boe) 50,827 48,839 48,850 47,653 Total production (mboe) 4,574 4,444 4,494 4,384 Average realized price per boe ($ per boe) 45.21 38.60 36.65 35.78 Operating netback per boe ($ per boe) 26.50 21.11 20.54 20.43

Management Appointments

During the third quarter, Pengrowth made several senior management appointments bringing additional operation expertise to the Pengrowth team reflecting Pengrowth's commitment to operational excellence, effective strategic planning and creation of value through further development of Pengrowth's reserves. In each case, the new members of senior management have strong technical backgrounds with leading companies in the oil and gas industry. In the current environment of above average oil and gas prices, Pengrowth's strategic objectives include focused attention on Pengrowth's existing properties and appropriate application of new technology.

- Mr. Larry B. Strong has been appointed Vice President, Geosciences and an Officer of Pengrowth Corporation. He will focus on exploitation and exploration opportunities on Pengrowth's existing land base and will add value in conjunction with new acquisitions. Mr. Strong is a highly qualified geologist with both solid management and business experience. Mr. Strong brings over 20 years experience in Earth Sciences beginning his career as a Petroleum Geologist/Geophysicist with Chevron Canada Resources. Prior to joining Pengrowth, Mr. Strong served in senior geosciences roles at NCE Resources Group and Waterous & Co. and most recently served as an Officer and Vice President of Geosciences at Petrofund Corporation. Mr. Strong holds a Bachelor of Science (Specialist) in Geology and a Minor in Computer Science from Brandon University.

- Mr. William Christensen who is presently consulting to Pengrowth will become Vice President, Strategic Planning and Reservoir Exploitation and an Officer of Pengrowth Corporation upon Canadian immigration approval. Mr. Christensen's responsibilities will include a comprehensive review of past acquisitions and the effectiveness of Pengrowth's exploitation and development programs as a basis for planning effective future initiatives to enhance unitholder value. Mr. Christensen has over 25 years in the energy sector including broad international experience, both in operations and the completion of transactions. Prior to a recent relocation to Houston, Mr. Christensen served as Vice President Planning with Northrock Resources. Before joining Northrock, Mr. Christensen served in several capacities during a long and varied career with Unocal Corporation. Mr. Christensen holds a Masters in Business Administration from UCLA and a Bachelor of Science in Mechanical Engineering from Oregon State University.

- Mr. James Causgrove has been appointed Vice President, Production and Operations and an Officer of Pengrowth Corporation. He will have broad responsibilities for the operating activities of Pengrowth Corporation and Pengrowth's ongoing development and growth. Mr. Causgrove has over 25 years of experience with Chevron, where he most recently held the position of Manager, New Growth Opportunities Group and Senior Vice President and Chief Operating Officer of Central Alberta Midstream. Mr. Causgrove has a broad operational background in drilling, production engineering and midstream areas across the Western Canadian Sedimentary Basin as well as significant experience in the property divestiture market and the analysis of potential corporate and acquisitions and divestitures, including the recent sale of Central Alberta Midstream. Mr. Causgrove holds a Bachelor of Science in Chemical Engineering and is a registered professional engineer.

Outlook

Based on third quarter 2005 production results, Pengrowth expects daily average production of approximately 57,500 to 58,500 boe per day for the full year 2005. This estimate incorporates production additions from the Swan Hills Unit No. 1 and Crispin acquisitions, Pengrowth's 2005 development program and two condensate shipments from SOEP in the fourth quarter of 2005, offset by normal production declines and non-core property divestitures.

Total operating costs for 2005 are expected to increase to approximately $210 to $220 million including a full year of costs from the Murphy acquisition and those associated with the Swan Hills Unit No. 1 and Crispin acquisitions. Assuming Pengrowth's average production results for 2005 are as forecast above, Pengrowth now estimates 2005 operating costs per boe of between $9.80 and $10.45 and combined G&A and management fees of approximately $2.05 to $2.15 per boe.

Pengrowth currently anticipates capital expenditures for maintenance and development of approximately $185 million for 2005.

Pengrowth is pleased to announce an increase in monthly distributions during the fourth quarter to $0.25 per trust unit beginning with the December 15, 2005 distribution which is expected to result in a payout ratio of 73 to 76 percent for the full year 2005.

Pengrowth is continually evaluating its portfolio for optimization opportunities. In addition to the property sales which closed in the third quarter of 2005, purchase and sale agreements have been executed with several parties to acquire from Pengrowth non-core properties with associated production of approximately 400 boe per day for gross proceeds of approximately $20 million, before adjustments. These divestments were previously disclosed in the second quarter of 2005 and are now expected to close in the fourth quarter.

Pengrowth has sought and achieved compliance with the applicable legal and regulatory provisions. On July 27, 2004, Pengrowth Trust implemented a Class A and Class B trust unit structure to manage the level of non-resident ownership of the Fund. Subsequent to implementation of the structure, and prior to June 1, 2005, Pengrowth achieved foreign ownership below a threshold of 49.75% in accordance with an advance tax ruling by Canada Revenue Agency essentially confirming the status of Pengrowth Trust as a Mutual Fund Trust under the Income Tax Act (Canada).

To the extent that Class A trust units in the future represent less than the ownership threshold of 49.75 percent, conversion of Class B trust units to Class A trust units is permissible under the Trust Indenture. Pengrowth proposed a new form of reservation system that was approved in principle by unitholders at the Annual & Special Unitholder Meeting on April 26, 2005 in order to provide all unitholders with an equal and orderly opportunity to convert Class B trust units into Class A trust units. Pengrowth is currently working with Computershare Trust Company of Canada to design an appropriate system and proposes to make a press release in respect to the implementation of the system during the fourth quarter.

In connection with statements made in the 2005 Federal Budget, the Department of Finance released a consultation paper (the "Consultation Paper") on September 8, 2005 titled Tax and Other Issues Related to Publicly Listed Flow-Through Entities. The Consultation Paper launched a process of discussion and third-party input on the impact of publicly listed income trusts and other flow-through entities (FTEs) on federal tax revenues and the Canadian economy. Although not specifically referred to, FTEs could include royalty trusts such as Pengrowth Energy Trust. The consultation process will seek input on a number of questions, including:

- Does the tax advantage of FTEs relative to public corporations have a significant impact on how businesses are organized in Canada? - Have FTEs had a significant impact on tax revenues? Is there potential for revenue losses to grow in the years to come? - What impacts are FTEs having on investment decision and the allocation of capital in Canada? Is the overall impact on the economy positive or negative? - Given the important role that tax-exempt investors play in Canadian capital markets, and could play in the FTE market, what impact could this have on government revenues and economic efficiency? - Overall, are there public policy concerns about FTEs and how the tax system influences their existence and, if so, what actions would be considered to address these concerns?

This process will not include separate consultations announced by the Department of Finance on December 6, 2004 regarding the 2004 Federal Budget proposals with respect to mutual funds maintained primarily for the benefit of non-residents. The Department of Finance has invited submissions until December 31, 2005. Subsequent to the consultation process, the Minister of Finance announced there would be a moratorium on the issuance of tax ruling to FTEs.

Pengrowth has complied with the applicable legal and regulatory provisions. On July 27, 2004, Pengrowth Trust implemented a Class A and Class B trust unit structure to manage the level of non-resident ownership of the Fund. Subsequent to implementation of the structure, and prior to June 1, 2005, Pengrowth achieved foreign ownership below a threshold of 49.75% in accordance with an advance tax ruling by Canada Revenue Agency essentially confirming the status of Pengrowth Trust as a Mutual Fund Trust under the Income Tax Act (Canada).

The royalty trust industry has become an important element of Canada's capital markets and a significant contributor to the capital resources available to the petroleum industry and the efficiency of its operations. Throughout its 17 year history Pengrowth has fostered a culture of innovation, operational excellence and environmental stewardship acquiring and effectively managing legacy oil and natural gas properties in Canada. During that period Pengrowth has completed more than 50 acquisitions in accordance with a series of tax rulings and policy pronouncements by CRA and the Department of Finance while fostering relationships with all levels of government defined by consultation, cooperation and compliance.

Pengrowth will continue its approach of consultation and intends to make specific submissions to the Department of Finance in both consultation processes on the benefits of achieving certainty and maintaining the tax and regulatory regime governing royalty trusts that has enhanced the value and efficiency of the petroleum industry and enabled Canadians across the country to participate in that process.

CONFERENCE CALL AND CONTACT INFORMATION

Pengrowth will hold a conference call beginning at 11:00 A.M. Eastern Time (9:00 A.M. Mountain Time) on Friday, November 4, 2005 during which Management will review Pengrowth's 2005 third quarter financial and operating results and respond to inquiries from the investment community. To participate callers may dial (866) 898-9626 or Toronto local (416) 340-2216. To ensure timely participation in the teleconference callers are encouraged to dial in 10 to 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 www.pengrowth.com. The webcast will be archived through November 4, 2006. A telephone replay will be available through to midnight Eastern Time on Friday, November 11, 2005 by dialing (800) 408-3053 or Toronto local (416) 695-5800 and entering passcode number 3165707. For further information about Pengrowth, please visit our website www.pengrowth.com or contact:

Investor Relations, E-mail: investorrelations@pengrowth.com

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

Operations Review

REVIEW OF DEVELOPMENT ACTIVITIES (All volumes stated below are net to Pengrowth unless otherwise stated)

NORTHEAST BRITISH COLUMBIA

- Successfully drilled one oil well at Oak Baldonnel (100 percent working interest) and testing is currently underway.

- Completed Reservoir Simulation on Oak Cecil C Pool. Identified an infill drilling opportunity for the fourth quarter.

- Delineated Notikewin play over Bulrush area for first quarter 2006 activity.

- Sirius/Prespatou Gas Facility was brought online in July (90 percent working interest) with 4.0 mmcf per day gross throughput.

- Two non-operated recompletions (33.33 percent working interest) yielded 1.0 mmcf per day at Bonanza and will be tied-in during the fourth quarter.

- Two parcels were purchased at Crown land sales for prospects to be drilled in 2006.

SOUTHERN

- A 100 percent working interest well in the West Pembina area came on production at 1.0 mmcf per day.

- A non-operated gas well (20 percent working interest) was tested in the Notikewin formation at 320 mcf per day.

- Pengrowth increased its undeveloped land position at West Pembina during the quarter.

- During the third quarter, 44 wells of a 52 well program for the Milk River and Medicine Hat formations at Princess, Alberta were drilled, completed, fracture stimulated and tied-in (mainly in the third quarter). These wells should come on production November 1, 2005. The drilling of the remaining eight wells was deferred to 2006.

- Wells which came on during the third quarter include two Belly River (284 mcf and 250 mcf per day), one Ellerslie (460 mcf per day) and one additional well was drilled and is awaiting completion.

- Imperial Oil Resources served notice of their intent to commence the drilling of a gas well at Quirk Creek. Pengrowth is participating in this well with a working interest of 68 percent.

CENTRAL

Judy Creek

- A new miscible pattern is beginning to see response with incremental oil production of 283 barrels of oil per day.

- One producer reactivation at 25 barrels of oil per day.

- Pengrowth acquired 4,000 acres at Crown land sales on parcels directly offsetting the Judy Creek A & B pools.

- Two farm-in wells were drilled by industry partners.

- The Judy Creek Plant Acid Gas Injection project is underway with the testing of a prospective injection well. The acid gas compressor is on order and Alberta Environment has granted an extension to the current plant license to July, 2006 to allow time for the implementation of this project.

McLeod

- One well drilled at a Gething location was dry and abandoned.

Weyburn Unit

- Fourteen oil wells were drilled in the third quarter. These were a combination of horizontals and vertical re-entries for horizontal production. Production response to the drilling and CO2 injection programs has been favourable.

Hanlan

- At the Hanlan Unit and Hanlan Robb Gas Plant one gas well was drilled and expected onstream in September, 2005. The initial in-line flow test (3.3 mmcf per day gross) is now being analyzed by the operator and is slated to come onstream in February 2006.

South Swan Hills Unit

- Two wells were rig released from drilling in the third quarter. Plans are in place to test these multi-legged horizontal oil wells in the east platform area. The operator has not yet reported results.

Swan Hills Unit No. 1

- The final three oil producers in a seven well dril

Source: Business Wire

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