Peyto Energy Trust
TSX : PEY.UN

November 11, 2009 16:30 ET

Peyto Energy Trust Announces Third Quarter 2009 Results

CALGARY, ALBERTA--(Marketwire - Nov. 11, 2009) - Peyto Energy Trust (TSX:PEY.UN) ("Peyto") is pleased to present the operating and financial results for the third quarter of the 2009 fiscal year. Peyto is in the business of exploring, developing and producing natural gas in Western Canada. Virtually all of the high quality natural gas assets that Peyto owns today, it found and developed, generating profits that would be difficult to match through acquisition activity. This business strategy makes Peyto unique.

The foundation of the Trust is built on Peyto's high quality natural gas reserves and can be characterized as follows:

- Long reserve life - Proved Producing 14 years, Total Proved 17 years, Proved plus Probable 23 years

- Low operating costs - $0.41/mcfe ($2.43/boe), three months ending September 30, 2009

- High heat content natural gas stream - Realized revenue of $4.16/mcfe ($24.97/boe) before hedging, $6.20/mcfe ($37.18/boe) after hedging, three months ending September 30, 2009

- Low base general and administrative costs - $0.15/mcfe ($0.93/boe), three months ending September 30, 2009

- High field netback - $5.22/mcfe ($31.32/boe) or 84% of revenue, three months ending September 30, 2009

- High level of operatorship - operates over 98% of its production

- Cash distributions - cash distributions of $41.4 million were 91% of funds from operations for the three months ending September 30, 2009

- Since inception, Peyto has raised a total of $500 million issuing units from treasury, accumulated earnings of $1.039 billion, and distributed $931 million to unitholders

- Transparent capital structure - no convertible debentures, no exchangeable shares, no stock options, no warrants

Despite the lowest natural gas price environment since 2002, the third quarter of 2009 was highlighted by profitable capital spending, strong margins and stable distributions. Third quarter highlights are as follows:

- Capital expenditures - $28.7 million was invested into finding and developing new natural gas reserves, up from $4.7 million in the previous quarter, but down from $62.3 million in Q3 2008

- Natural gas prices before hedges were 66% lower in Q3 2009 with prices averaging $3.31/mcf versus $9.87/mcf in Q3 2008. After hedging, Q3 2009 gas prices were 35% lower at $5.74/mcf versus $8.81/mcf for the previous period

- Cash netbacks for the quarter averaged $4.61/mcfe ($27.65/boe), versus $6.77/mcfe ($40.64/boe) a year ago, which represents 74% of revenue

- Production - decreased 11% from 119,520 mcfe/d (19,920 boe/d) in the third quarter of 2008 to 106,755 mcfe/d (17,792 boe/d) in the third quarter of 2009

- Per unit funds from operations - decreased 44% from the previous year to $0.39/unit

- Hedging - a $20.0 million gain for the three months ending September 30, 2009 was realized

- Net debt decreased 13% from $490 million in Q3 2008 to $424 in Q3 2009. This leaves available borrowing capacity of $126 million on bank lines of $550 million, secured by over $2.7 billion in Proved Producing assets (2008 PP NPV5)

- A total of $41.4 million or $0.36/unit was distributed to unitholders in the third quarter of 2009. For 2009 to date, $122 million has been distributed out of $120 million in earnings

Natural gas volumes recorded in thousand cubic feet (mcf) are converted to barrels of oil equivalent (boe) using the ratio of six (6) thousand cubic feet to one (1) barrel of oil (bbl). Natural gas liquids and oil volumes in barrel of oil (bbl) are converted to thousand cubic feet equivalent (mcfe) using a ratio of one (1) barrel of oil to six (6) thousand cubic feet. This could be misleading if used in isolation as it is based on an energy equivalency conversion method primarily applied at the burner tip and does not represent a value equivalency at the wellhead.



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3 Months Ended September 30 %
2009 2008 Change
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Operations
Production
Natural gas (mcf/d) 89,259 100,324 (11)%
Oil & NGLs (bbl/d) 2,916 3,199 (9)%
Thousand cubic feet equivalent
(mcfe/d @ 1:6) 106,755 119,520 (11)%
Barrels of oil equivalent (boe/d
@ 6:1) 17,792 19,920 (11)%
Product prices
Natural gas ($/mcf) 5.74 8.81 (35)%
Oil & NGLs ($/bbl) 51.06 99.28 (49)%
Operating expenses ($/mcfe) 0.41 0.42 (2)%
Transportation ($/mcfe) 0.11 0.10 10%
Field netback ($/mcfe) 5.22 7.35 (29)%
General & administrative expenses
($/mcfe) 0.15 0.12 25%
Interest expense ($/mcfe) 0.46 0.46 -
Financial ($000, except per unit)
Revenue 60,860 110,537 (45)%
Royalties 4,507 23,930 (81)%
Funds from operations 45,263 74,485 (39)%
Funds from operations per unit 0.39 0.70 (44)%
Total distributions 41,371 47,664 (13)%
Total distributions per unit 0.36 0.45 (20)%
Payout ratio 91 64 42%
Earnings 26,976 64,834 (58)%
Earnings per diluted unit 0.24 0.61 (61)%
Capital expenditures 28,725 62,271 (54)%
Weighted average trust units
outstanding 114,920,194 105,920,194 8%
As at September 30
Net debt (before future
compensation expense
and unrealized hedging gains)
Unitholders' equity
Total assets
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Earnings 26,976 64,834
Items not requiring cash:
Future income tax expense (841) (4,910)
Depletion, depreciation and
accretion 17,966 18,640
Change in non-cash working
capital 5,726 2,873
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Cash flows from operating
activities 49,827 81,437
Provision for performance based
compensation 1,162 (4,079)
Change in non-cash working
capital (5,726) (2,873)
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Funds from operations (1) 45,263 74,485
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9 Months Ended September 30 %
2009 2008 Change
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Operations
Production
Natural gas (mcf/d) 91,791 99,872 (8)%
Oil & NGLs (bbl/d) 2,962 3,285 (10)%
Thousand cubic feet equivalent
(mcfe/d @ 1:6) 109,565 119,582 (8)%
Barrels of oil equivalent (boe/d
@ 6:1) 18,261 19,930 (8)%
Product prices
Natural gas ($/mcf) 6.54 8.87 (26)%
Oil & NGLs ($/bbl) 46.30 96.46 (52)%
Operating expenses ($/mcfe) 0.43 0.43 -
Transportation ($/mcfe) 0.11 0.11 -
Field netback ($/mcfe) 5.58 7.39 (24)%
General & administrative expenses
($/mcfe) 0.19 0.17 12%
Interest expense ($/mcfe) 0.40 0.51 (22)%
Financial ($000, except per unit)
Revenue 201,299 329,508 (39)%
Royalties 18,214 70,055 (74)%
Funds from operations 149,397 219,553 (32)%
Funds from operations per unit 1.37 2.07 (34)%
Total distributions 121,891 139,067 (12)%
Total distributions per unit 1.12 1.31 (15)%
Payout ratio 82 63 30%
Earnings 119,738 128,686 (7)%
Earnings per diluted unit 1.10 1.21 (9)%
Capital expenditures 46,432 116,857 (60)%
Weighted average trust units
outstanding 109,085,029 105,876,470 3%
As at September 30
Net debt (before future
compensation expense
and unrealized hedging gains) 423,965 489,867 (13)%
Unitholders' equity 624,855 536,918 16%
Total assets 1,240,770 1,250,973 (1)%
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Earnings 119,738 128,686
Items not requiring cash:
Future income tax expense (26,378) 30,333
Depletion, depreciation and
accretion 54,261 55,768
Change in non-cash working
capital 4,500 (14,780)
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Cash flows from operating
activities 152,121 200,007
Provision for performance based
compensation 1,776 4,766
Change in non-cash working
capital (4,500) 14,780
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Funds from operations (1) 149,397 219,553
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(1) Funds from operations - Management uses funds from operations to analyze
the operating performance of its energy assets. In order to facilitate
comparative analysis, funds from operations is defined throughout this
report as earnings before performance based compensation, non-cash and
non-recurring expenses. Management believes that funds from operations
is an important parameter to measure the value of an asset when combined
with reserve life. Funds from operations is not a measure recognized by
Canadian generally accepted accounting principles ("GAAP") and does not
have a standardized meaning prescribed by GAAP. Therefore, funds from
operations, as defined by Peyto, may not be comparable to similar
measures presented by other issuers, and investors are cautioned that
funds from operations should not be construed as an alternative to net
earnings, cash flow from operating activities or other measures of
financial performance calculated in accordance with GAAP. Funds from
operations cannot be assured and future distributions may vary.


Quarterly Review

Peyto increased activity in the third quarter of 2009, drilling 9 new gas wells (7 net working interest share) and bringing on stream 8 new zones (7.5 net). Drilling and completion activity accounted for $22.4 million of capital expenditures while wellsite equipment, facilities and pipelines accounted for $2.8 million. The Trust also invested $3.5 million into the acquisition of new lands with prospective drilling locations.

A natural gas price of $5.74/mcf and a liquids price of $51.06/bbl were realized in the third quarter of 2009, which included a hedging gain of $2.43/mcf. These prices were down 35% and 49%, respectively from the prior year period. Daily production for Q3 2009 averaged 89.3 mmcf of natural gas and 2,916 bbls of natural gas liquids, down 11% and 9% respectively from Q3 2008 as a result of natural declines and reduced capital investment. Combined operating costs of $0.41/mcfe and transportation expenses of $0.11/mcfe were consistent with the previous quarter and unchanged from Q3 2008. Royalties of $0.46/mcfe, or approximately 7% of revenue, represented a blend of older production subject to the New Royalty Framework as well as new volumes subject to the 5% maximum New Well Incentive. From April 1, 2009 to the end of the third quarter, Peyto has drilled a total of 29,800 net meters in Alberta for a total Drilling Royalty Credit of $6.0 million. Based on cumulative royalties paid for that same period, Peyto has accounted for a $3.4 million receivable from Alberta Energy (of which $1.2 million has been received to date).

Royalties, operating and transportation costs, G&A and interest expenses all combined for total cash costs of $1.59/mcfe in the third quarter 2009, which yields a corporate netback of $4.61/mcfe or $27.65/boe. This netback represents 74% of revenues which Peyto believes to be one of the highest margins in the industry.

Activity Update

Peyto has maintained a steady level of activity since the end of the third quarter with two drilling rigs active in the Deep Basin. The application of horizontal drilling combined with multi stage fracture treatments has now been applied to both the Cardium and Wilrich formations with encouraging initial results. The Trust plans to optimize the technical success of each of these operations while monitoring their production performance to confirm that greater profitability was also achieved with this approach. Fourth quarter production to date has averaged 114 mmcfe/d (19,000 boe/d) with the two horizontal wells contributing 3.9 mmcfe/d net (650 boe/d) or 3% of that total. Net capital expenditure for the horizontal wells to achieve this initial result was $5.7 million or $8,800 per boe/d.

Spot natural gas prices have recovered to a level where all of Peyto's wells are generating solid positive cashflow. As a result, there is no production currently shut in which requires better gas prices. New production additions will, however, continue to be brought on at the start of each month in order to maximize the benefits from the Royalty Incentive program.

For the balance of 2009 Peyto plans on having 3 to 4 drilling rigs active in the Trust's Deep Basin core areas. Two of these rigs are specifically designed to drill horizontal wells where multi-stage fracture stimulation techniques can be used. The Trust anticipates that, in addition to several vertical locations, at least 2 more horizontal wells will be drilled by year end. At current capital investment rates of approximately $10 million per month, Peyto expects to exit 2009 at a production rate similar to the previous two years. In 2009, Peyto has demonstrated superior efficiency with respect to the cost of new production additions, as shown in the following table:



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2004 2005 2006 2007 2008 2009F
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Capital Spending
($millions) $ 231 $ 358 $ 312 $ 122 $ 139 $ 80

Incremental Production
(Boe/d) 10,400 8,500 6,200 4,600 4,200 5,000

$000s per boe/d $ 22.2 $ 42.1 $ 50.3 $ 26.5 $ 33.1 $ 16.0
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Marketing

Daily AECO natural gas prices rose dramatically in early October 2009 from $2.53/GJ to $4.61/GJ. Alberta Monthly prices followed suit rising from $2.87/GJ in October to $4.64/GJ in November 2009 as supply shut-ins reaffirmed industry predictions that the overall North American natural gas price was below the cash costs of production, let alone the marginal cost of new supply. The futures price suggests that this marginal cost may be even higher still as the 2010 gas price is trading around US$5.30/mmbtu. A strong Canadian dollar only adds to the pressure on Canadian natural gas supplies to compete at this level. Fortunately, Peyto has a long history of both low production cost and low supply cost which affords it a strategic advantage in this increasingly competitive market. As the volatility in natural gas price continues, so does the need to smooth out this volatility in order to plan capital programs and set distribution levels. The Peyto marketing strategy of selling small portions of production, up to 24 months into the future, achieves this goal.

As at September 30, 2009, the Trust had committed to the future sale of 16,405,000 gigajoules (GJ) of natural gas at an average price of $6.56 per GJ or $7.68/mcf. Had these contracts been closed on September 30, 2009, the Trust would have realized a gain in the amount of $16.8 million.

Outlook

The outlook for natural gas has improved significantly since the last quarter with the expectation of falling North American supplies driving increasing commodity prices. Industry activity in Western Canada has yet to respond to these rising prices, so service costs remain attractive. The prospect of improved profitability with the use of horizontal wells and multi-stage fracture stimulations means Peyto's existing inventory of commercial drilling locations is rapidly expanding. In order to capitalize on this inventory, the preliminary 2010 capital budget has been established between $175 and $200 million, before the effect of Drilling Royalty Credits. With over half of this capital expected to be allocated to the horizontal program, Peyto anticipates that building new production in 2010 may be even more efficient than that demonstrated in 2009 and should deliver growth in production throughout the year. It is expected that this capital program can be funded with a combination of funds from operations, working capital, and available bank lines.

Peyto has now met with its advisors and determined that, barring any unforeseen legislative changes and pending unitholder and regulatory approval, the conversion of the Trust into a corporate form will likely occur effective December 31, 2010. This new structure will afford Peyto the continued ability to return profits from the success of the business to shareholders in the form of dividends.

Unitholders are encouraged to visit the Peyto website at www.peyto.com where there is a wealth of information designed to inform and educate investors. A monthly President's Report can also be found on the website which follows the progress of the capital program and the ensuing production growth.

Conference Call and Webcast

A conference call will be held with the senior management of Peyto to answer questions with respect to the 2009 third quarter financial results on Thursday, November 12th, 2009, at 9:00 a.m. Mountain Standard Time (MST), or 11:00 a.m. Eastern Standard Time (EST). To participate, please call 1- 416-340-8018 (Toronto area) or 1- 866-223-7781 for all other participants. The conference call will also be available on replay by calling 1-416-695-5800 (Toronto area) or 1-800-408-3053 for all other parties, using passcode 5317640. The replay will be available from 11:00 a.m. MST, 1:00 p.m. EST Thursday, November 12th, 2009 until midnight EST on Wednesday, November 19th, 2009. The conference call can also be accessed through the internet at http://events.digitalmedia.telus.com/peyto/111209/index.php. After this time the conference call will be archived on the Peyto Energy Trust website at www.peyto.com.

Management's Discussion and Analysis

A copy of the third quarter report to Unitholders, including the Management's Discussion and Analysis, and unaudited interim financial statements and related notes is available at http://www.peyto.com/news/Q32009MDandA.pdf and will be filed at SEDAR, www.sedar.com , at a later date.


Darren Gee, President and CEO

November 11, 2009

Certain information set forth in this document and Management's Discussion and Analysis, including management's assessment of Peyto's future plans and operations, contains forward-looking statements. By their nature, forward-looking statements are subject to numerous risks and uncertainties, some of which are beyond these parties' control, including the impact of general economic conditions, industry conditions, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other industry participants, the lack of availability of qualified personnel or management, stock market volatility and ability to access sufficient capital from internal and external sources. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Peyto's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits Peyto will derive therefrom.



Peyto Energy Trust

Consolidated Balance Sheets
($000)

(unaudited)

September 30, December 31,
2009 2008
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Assets
Current
Accounts receivable (Note 3 and 10) 47,392 65,662
Financial derivative instruments (Note 10) 13,954 27,788
Prepaid expenses and deposits 3,981 3,367
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65,327 96,817
Financial derivative instruments (Note 10) 2,834 2,458
Prepaid capital 1,787 3,069
Property, plant and equipment (Note 4) 1,170,822 1,177,902
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1,240,770 1,280,246
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Liabilities and Unitholders' Equity
Current
Accounts payable and accrued liabilities 41,548 48,854
Distributions payable 13,790 15,888
Provision for future performance based
compensation 976 -
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56,314 64,742
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Long-term debt (Note 5) 420,000 500,000
Provision for future performance based
compensation 799 -
Asset retirement obligations 10,228 9,479
Future income taxes 128,574 155,308
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559,601 664,787
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Unitholders' equity
Unitholders' capital (Note 6) 500,408 410,233

Accumulated earnings (Note 7) 108,085 110,238
Accumulated other comprehensive income 16,362 30,246
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124,446 140,484
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624,855 550,717
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1,240,770 1,280,246
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See accompanying notes

On behalf of the Board:
(signed) "Michael MacBean" (signed) "Darren Gee"
Director Director


Peyto Energy Trust

Consolidated Statements of Earnings
($000 except per unit amounts)

(unaudited)


Three Months Ended Nine Months Ended
September 30 September 30
2009 2008 2009 2008
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Revenue
Oil and gas sales 40,841 120,340 150,390 345,149
Realized gain (loss) on hedges 20,019 (9,803) 50,909 (15,641)
Royalties (4,507) (23,930) (18,214) (70,055)
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Petroleum and natural gas sales, net 56,353 86,607 183,085 259,453
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Expenses
Operating (Note 8) 3,982 4,658 12,739 14,203
Transportation 1,097 1,153 3,370 3,446
General and administrative(Note 9) 1,518 1,293 5,660 5,414
Future performance based compensation
provision 1,162 (4,079) 1,776 4,766
Interest on long term debt 4,493 5,018 11,919 16,837
Depletion, depreciation and accretion
(Note 4) 17,966 18,640 54,261 55,768
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30,218 26,683 89,725 100,434
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Earnings before taxes 26,135 59,924 93,360 159,019
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Taxes
Future income tax (recovery) expense (841) (4,910) (26,378) 30,333
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Earnings for the period 26,976 64,834 119,738 128,686
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Earnings per unit (Note 6)
Basic and diluted 0.24 0.61 1.10 1.22
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See accompanying notes


Peyto Energy Trust

Consolidated Statements of Comprehensive Income
($000 except per unit amounts)

(unaudited)

Three Months Ended Nine Months Ended
September 30 September 30
2009 2008 2009 2008
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Earnings for the period 26,976 64,834 119,738 128,686
Other comprehensive income (loss)
Change in unrealized gain (loss) on
cash flow hedges (2,497) 90,023 37,025 (1,267)
Realized (gain) loss on cash flow
hedges (20,019) 9,803 (50,909) 15,641
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Comprehensive income 4,460 164,660 105,854 143,060
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See accompanying notes


Peyto Energy Trust

Consolidated Statements of Accumulated Earnings and Accumulated Other
Comprehensive Income
($000)

(unaudited)

Three Months Ended Nine Months Ended
September 30 September 30
2009 2008 2009 2008
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Accumulated earnings, beginning of
period 122,480 90,021 110,238 117,572
Net earnings for the period 26,976 64,834 119,738 128,686
Distributions (Note 7) (41,371) (47,664) (121,891) (139,067)
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Accumulated earnings, end of period 108,085 107,191 108,085 107,191
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Accumulated other comprehensive
income (loss), beginning of period 38,878 (80,332) 30,246 5,119
Other comprehensive income (loss) (22,516) 99,826 (13,884) 14,375
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Accumulated other comprehensive
income, end of period 16,362 19,494 16,362 19,494
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See accompanying notes

Peyto Energy Trust

Consolidated Statements of Cash Flows
($000)

(unaudited)

Three Months Ended Nine Months Ended
September 30 September 30
2009 2008 2009 2008
----------------------------------------------------------------------------
Cash provided by (used in)
Operating Activities
Earnings for the period 26,976 64,834 119,738 128,686
Items not requiring cash:
Future income tax expense (841) (4,910) (26,378) 30,333
Depletion, depreciation and accretion 17,966 18,640 54,261 55,768
Change in non-cash working capital
related to operating activities 5,726 2,873 4,500 (14,780)
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49,827 81,437 152,121 118,570
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Financing Activities
Issuance of trust units - - 94,500 3,932
Issuance costs (17) - (5,106) -
Distributions declared (Note 7) (41,371) (47,664) (121,891) (139,067)
Increase (decrease) in bank debt (40,000) - (80,000) 20,000
Change in non-cash working capital
related to financing activities - - (2,097) 1,088
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(81,388) (47,664) (114,594) (114,047)
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Investing Activities
Additions to property, plant and
equipment (28,725) (62,271) (46,432) (116,858)
Change in non-cash working capital
related to investing activities 18,722 22,772 8,905 10,351
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(10,003) (39,499) (37,527) (106,507)
----------------------------------------------------------------------------
Net increase (decrease) in cash (41,564) (5,726) - (20,547)
Cash, beginning of period 41,564 5,726 - 20,547
----------------------------------------------------------------------------
Cash, end of period - - - -
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See accompanying notes


Peyto Energy Trust

Notes to Consolidated Financial Statements

(unaudited)

September 30, 2009 and 2008

1. Summary of Significant Accounting Policies

The unaudited interim consolidated financial statements of Peyto Energy Trust (the "Trust" or "Peyto") follow the same accounting policies as the most recent annual audited consolidated financial statements. The interim consolidated financial statement note disclosures do not include all of those required by Canadian generally accepted accounting principles ("GAAP") applicable for annual financial statements. Accordingly, these interim financial statements should be read in conjunction with the 2008 audited consolidated financial statements.

These financial statements include the accounts of Peyto Energy Trust and its wholly owned subsidiaries, Peyto Exploration & Development Corp., Peyto Operating Trust, Peyto Energy Limited Partnership and Peyto Energy Administration Corp.

2. Changes in Accounting Policies

Current Year Accounting Changes

Goodwill and Intangible Assets

On January 1, 2009, the Trust retrospectively adopted the Canadian Institute of Chartered Accountants (CICA) Section 3064, Goodwill and Intangible Assets issued by the Accounting Standards Board ("AcSB"). This section clarifies the criteria for the recognition of assets, intangible assets and internally developed intangible assets. Adoption of this standard did not have an impact the Trust's results of operations or financial position.

Business Combinations

On January 1, 2009, the Trust prospectively adopted CICA Section 1582, Business Combinations issued by the AcSB. This section establishes principles and requirements of the acquisition method for business combinations and related disclosures. Adoption of this statement did not have an impact on the Trust's results of operations or financial position.

Consolidated Financial Statements and Non-Controlling Interests

On January 1, 2009, the Trust adopted CICA Sections 1601, Consolidated Financial Statements, and 1602, Non-Controlling Interests issued by the AcSB. Section 1601 establishes standards for the preparation of consolidated financial statements. Section 1602 provides guidance on accounting for non-controlling interests in consolidated financial statements subsequent to a business combination. Adoption of this statement did not have an impact on the Trust's results of operations or financial position.

Credit Risk and the Fair Value of Financial Assets and Financial Liabilities

Effective January 1, 2009, the Trust adopted the CICA Emerging Issues Committee (EIC) Abstract No.173, Credit Risk and the Fair Value of Financial Assets and Financial Liabilities (EIC 173). EIC 173 clarifies how an entity's own credit risk and that of the relevant counterparty should be taken into account in determining the fair value of financial assets and financial liabilities, including derivative instruments. The new guidance did not have any impact on the financial position or earnings of the Trust.

Pending Accounting Pronouncements

Financial Instruments - Disclosures

In May 2009, the CICA amended Section 3862, Financial Instruments - Disclosures, to include additional disclosure requirements about fair value measurement for financial instruments and liquidity risk disclosures. These amendments require a three level hierarchy that reflects the significance of the inputs used in making the fair value measurements. Fair values of assets and liabilities included in Level 1 are determined by reference to quoted prices in active markets for identical assets and liabilities. Assets and liabilities in Level 2 include valuations using inputs other than quoted prices for which all significant outputs are observable, either directly or indirectly. Level 3 valuations are based on inputs that are unobservable and significant to the overall fair value measurement. These amendments are effective for the Trust on December 31, 2009.

Financial Instruments - Recognition and Measurement

In July 2009, the CICA amended Section 3855, Financial Instruments - Recognition and Measurement, to prohibit the reclassification of a financial asset out of the held-for-trading category when the fair value of the embedded derivative in a combined contract cannot be reasonably measured. Amendments to this section also include a revised definition of "loans and receivables" and, provided that certain conditions have been met, permits reclassification of financial assets from the held-for-trading and available-for-sale categories into the loans and receivables category. The amendments also provide one method of assessing impairment for all financial assets regardless of classification. These amendments are effective for the Trust on December 31, 2009.



3. Accounts Receivable

September 30, December 31,
($000) 2009 2008
----------------------------------------------------------------------------
Accounts receivable - general 40,124 58,394
Accounts receivable - income taxes 7,268 7,268
----------------------------------------------------------------------------
47,392 65,662
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Canada Revenue Agency ("CRA") has conducted an audit of restructuring costs claimed as a result of the Trust conversion in 2003 that has resulted in the reclassification of $41.0 million dollars in employment related costs as eligible capital. In October, 2008, the Trust received a notice of reassessment from the CRA and paid an amount of $7.3 million related to this audit. Based upon consultation with legal counsel, Management's view is that CRA's position has no merit. A notice of appeal was filed May 19, 2009 and the appeal has been denied. Examinations for discovery are being scheduled.



4. Property, Plant and Equipment

September 30, December 31,
($000) 2009 2008
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Property, plant and equipment 1,598,210 1,551,789
Accumulated depletion and depreciation (427,388) (373,887)
----------------------------------------------------------------------------
1,170,822 1,177,902
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----------------------------------------------------------------------------


At September 30, 2009 costs of $24.4 million (December 31, 2008 - $36.8 million) related to undeveloped land have been excluded from the depletion and depreciation calculation.

5. Long-Term Debt

The Trust has a syndicated $550 million extendible revolving credit facility with a stated term date of April 30, 2010. The facility is made up of a $20 million working capital sub-tranche and a $530 million production line. The facilities are available on a revolving basis for a period of at least 364 days and upon the term out date may be extended for a further 364 day period at the request of the Trust, subject to approval by the lenders. In the event that the revolving period is not extended, the facility is available on a non-revolving basis for a further one year term, at the end of which time the facility would be due and payable. Outstanding amounts on this facility bear interest at rates determined by the Trust's debt to cash flow ratio that range from prime to prime plus 0.75% for debt to earnings before interest, taxes, depreciation, depletion and amortization (EBITDA) ratios ranging from less than 1:1 to greater than 2.5:1. A General Security Agreement with a floating charge on land registered in Alberta is held as collateral by the bank. The average borrowing rate for the three and nine months ended September 30, 2009 was 4.3% and 3.3% respectively (2008 - 4.5% and 5.1% respectively).



6. Unitholders' Capital

Authorized: Unlimited number of voting trust units

Issued and Outstanding
Trust Units (no par value) ($000) Number of Units Amount
----------------------------------------------------------------------------
Balance, December 31, 2008 105,920,194 410,233
Trust units issued 9,000,000 94,500
Trust unit issuance costs (net of tax) - (4,325)
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Balance, September 30, 2009 114,920,194 500,408
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On June 26, 2009, Peyto closed an offering of 9,000,000 trust units at a price of $10.50 per trust unit, receiving net proceeds of $89.4 million.

Per Unit Amounts

Earnings per unit have been calculated based upon the weighted average number of units outstanding for three months ended September 30, 2009 of 114,920,194 (2008 - 105,920,194) and for the nine months ended September 30, 2009 of 109,085,029 (2008 - 105,861,789). There are no dilutive instruments outstanding.

7. Accumulated Distributions

The Trust declared total distributions to the unitholders in the aggregate amount of $41.4 million in the three months ended September 30, 2009 (2008 - total $47.7 million) and $121.9 million for the nine months ended September 30, 2009 (2008 - total $139.1 million) in accordance with the following schedule:



Production Period Record Date Distribution Date Per Unit (1)
----------------------------------------------------------------------------
January 2009 January 31, 2009 February 13, 2009 $ 0.15
February 2009 February 28, 2009 March 13, 2009 $ 0.12
March 2009 March 31, 2009 April 15, 2009 $ 0.12
April 2009 April 30, 2009 May 15, 2009 $ 0.12
May 2009 May 31, 2009 June 15, 2009 $ 0.12
June 2009 June 30, 2009 July 15, 2009 $ 0.12
July 2009 July 31, 2009 August 14, 2009 $ 0.12
August 2009 August 31, 2009 September 15, 2009 $ 0.12
September 2009 September 30, 2009 October 15, 2009 $ 0.12
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Distributions per trust unit reflect the sum of the per trust unit
amounts declared monthly to unitholders.

Accumulated Earnings and Distributions

($000) September 30, December 31,
2009 2008
----------------------------------------------------------------------------
Accumulated earnings (before
distributions), beginning of period 919,435 740,038
Earnings for the period 119,738 179,397
----------------------------------------------------------------------------
Total accumulated earnings (before
distributions) 1,039,173 919,435
Total accumulated distributions (931,088) (809,197)
----------------------------------------------------------------------------
Accumulated earnings (after
distributions), end of period 108,085 110,238
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----------------------------------------------------------------------------


8. Operating Expenses

The Trust's operating expenses include all costs with respect to day-to-day well and facility operations. Processing and gathering income related to joint venture and third party natural gas reduces operating expenses.



Three Months Ended Nine Months Ended
September 30 September 30
($000) 2009 2008 2009 2008
----------------------------------------------------------------------------
Field expenses 6,839 7,724 20,962 22,602
Processing and gathering income (2,857) (3,066) (8,223) (8,399)
----------------------------------------------------------------------------
Total operating costs 3,982 4,658 12,739 14,203
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----------------------------------------------------------------------------


9. General and Administrative Expenses (G & A) General and administrative
expenses are reduced by operating and capital overhead recoveries on
operated properties.

Three Months Ended Nine Months Ended
September 30 September 30
($000) 2009 2008 2009 2008
----------------------------------------------------------------------------
General and administrative
expenses 2,343 2,485 7,351 7,953
Overhead recoveries (825) (1,192) (1,691) (2,539)
----------------------------------------------------------------------------
Net general and administrative
expenses 1,518 1,293 5,660 5,414
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----------------------------------------------------------------------------


10. Financial Instruments and Risk Management

Market Risk

Market risk is the risk that changes in market prices will affect the Trust's net earnings or the value of its financial instruments. Market risk is comprised of commodity price risk and interest rate risk. The objective of market risk management is to manage and control its exposures within acceptable limits, while maximizing returns. The Trust's objectives, processes and policies for managing market risks have not changed from the previous year.

Commodity Price Risk Management

The Trust is a party to certain derivative financial instruments, including fixed price contracts. The Trust enters into these contracts with well-established counterparties for the purpose of protecting a portion of its future earnings and cash flows from operations from the volatility of commodity prices. The Trust believes the derivative financial instruments are effective as hedges, both at inception and over the term of the instrument, as the term and notional amount do not exceed the Trust's firm commitment or forecasted transaction and the underlying basis of the instrument correlates highly with the Trust's exposure. A summary of contracts outstanding in respect of the hedging activities at September 30, 2009 are as follows:



Natural Gas Daily Price
Period Hedged Type Volume (CAD)
----------------------------------------------------------------------------
April 1, 2009 to October 31, 2009 Fixed price 5,000 GJ $ 7.85/GJ
April 1, 2009 to October 31, 2009 Fixed price 5,000 GJ $ 8.12/GJ
April 1, 2009 to October 31, 2009 Fixed price 5,000 GJ $ 8.95/GJ
April 1, 2009 to October 31, 2009 Fixed price 5,000 GJ $ 9.30/GJ
April 1, 2009 to October 31, 2009 Fixed price 5,000 GJ $ 10.20/GJ
April 1, 2009 to October 31, 2009 Fixed Price 5,000 GJ $ 7.50/GJ
April 1 , 2009 to March 31, 2010 Fixed Price 5,000 GJ $ 7.65/GJ
April 1 , 2009 to March 31, 2010 Fixed Price 5,000 GJ $ 6.90/GJ
November 1, 2009 to March 31, 2010 Fixed Price 5,000 GJ $ 8.39/GJ
November 1, 2009 to March 31, 2010 Fixed Price 5,000 GJ $ 8.35/GJ
November 1, 2009 to March 31, 2010 Fixed price 5,000 GJ $ 5.25/GJ
November 1, 2009 to October 31, 2010 Fixed price 5,000 GJ $ 5.20/GJ
November 1, 2009 to October 31, 2010 Fixed price 5,000 GJ $ 5.00/GJ
November 1, 2009 to March 31, 2011 Fixed Price 5,000 GJ $ 6.20/GJ
November 1, 2010 to March 31, 2011 Fixed Price 5,000 GJ $ 8.91/GJ
November 1, 2010 to March 31, 2011 Fixed Price 5,000 GJ $ 9.15/GJ
November 1 , 2009 to March 31, 2011 Fixed price 5,000 GJ $ 5.81/GJ
April 1, 2010 to October 31, 2010 Fixed price 5,000 GJ $ 6.10/GJ
----------------------------------------------------------------------------


As at September 30, 2009, the Trust had committed to the future sale of 16,405,000 gigajoules (GJ) of natural gas at an average price of $6.56 per GJ or $7.68 per mcf. Had these contracts been closed on September 30, 2009, the Trust would have realized a gain in the amount of $16.8 million. If the AECO gas price on September 30, 2009 were to increase by $1/GJ, the unrealized gain on these closed contracts would change by approximately $16.4 million. An opposite change in commodity prices rates will result in an opposite impact on earnings which would have been reflected in the other comprehensive income of the Trust.

Interest rate risk

The Trust is exposed to interest rate risk in relation to interest expense on its revolving credit facility. Currently, the Trust has not entered into any agreements to manage this risk. If interest rates applicable to floating rate debt were to have increased by 100 bps (1%) it is estimated that the Trust's earnings for the three and nine month periods ended September 30, 2009 would decrease by $1.0 million and $3.6 million, respectively. An opposite change in interest rates will result in an opposite impact on earnings.

Fair Values of Financial Assets and Liabilities

The Trust's financial instruments include cash, accounts receivable, financial derivative instruments, current liabilities (excluding future income tax), provision for future performance based compensation and long term debt. At September 30, 2009, the carrying value of cash, accounts receivable, financial derivative instruments, current liabilities and provision for future performance based compensation approximate their fair value. The carrying value of the long term debt approximates its fair value due to the floating rate of interest charged under the credit facility.

Credit Risk

A substantial portion of the Trust's accounts receivable is with petroleum and natural gas marketing entities.

Industry standard dictates that commodity sales are settled on the 25th day of the month following the month of production. The Trust generally extends unsecured credit to these companies, and therefore, the collection of accounts receivable may be affected by changes in economic or other conditions and may accordingly impact the Trust's overall credit risk. Management believes the risk is mitigated by the size, reputation and diversified nature of the companies to which they extend credit. The Trust has not previously experienced any material credit losses on the collection of accounts receivable. Of the Trust's revenue for the three and nine months ended September 30, 2009, approximately 85% and 86% was received from four companies (September 30, 2008 - 80% and 80%, three companies) respectively. Of the Trust's significant individual accounts receivable at September 30, 2009, approximately 27% was due from four companies (December 31, 2008 - 43%, three companies). The maximum exposure to credit risk is represented by the carrying amount on the balance sheet. There are no material financial assets that the Trust considers past due and no accounts have been written off.

The Trust may be exposed to certain losses in the event of non-performance by counterparties to commodity price contracts. The Trust mitigates this risk by entering into transactions with counter-parties that have investment grade credit ratings, in accordance with policy as established by the Board of Directors. Counterparties for derivative instrument transactions are limited to financial institutions which are all members of our syndicated credit facility.

The Trust assesses quarterly if there should be any impairment of financial assets. At September 30, 2009, there was no impairment of any of the financial assets of the Trust.

Liquidity Risk

Liquidity risk includes the risk that, as a result of operational liquidity requirements:

- The Trust will not have sufficient funds to settle a transaction on the due date;

- The Trust will be forced to sell financial assets at a value which is less than what they are worth; or

- The Trust may be unable to settle or recover a financial asset at all.

The Trust's operating cash requirements, including amounts projected to complete our existing capital expenditure program, are continuously monitored and adjusted as input variables change. These variables include, but are not limited to, available bank lines, oil and natural gas production from existing wells, results from new wells drilled, commodity prices, cost overruns on capital projects and changes to government regulations relating to prices, taxes, royalties, land tenure, allowable production and availability of markets. As these variables change, liquidity risks may necessitate the need for the Trust to conduct equity issues or obtain project debt financing.



The following are the contractual maturities of financial liabilities as at
September 30, 2009:
less than 1-2 2-5
($000s) 1 Year Years Years Thereafter
----------------------------------------------------------------------------
Accounts payable and accrued
liabilities 41,548
Distributions payable 13,790
Provision for future
performance based compensation 976 799
Long-term debt(1) 420,000
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1)Revolving credit facility renewed annually (see Note 5)


11. Capital Disclosures

The Trust's objectives when managing capital are: (i) to maintain a flexible capital structure, which optimizes the cost of capital at acceptable risk; and (ii) to maintain investor, creditor and market confidence to sustain the future development of the business.

The Trust manages its capital structure and makes adjustments to it in light of changes in economic conditions and the risk characteristics of our underlying assets. The Trust considers its capital structure to include unitholders' equity, debt and working capital. To maintain or adjust the capital structure, the Trust may from time to time, issue trust units, raise debt and/or adjust its capital spending and distribution levels to manage its current and projected debt levels. The Trust monitors capital based on the following non-GAAP measures: current and projected debt to earnings before interest, taxes, depreciation, depletion and amortization ("EBITDA") ratios, payout ratios and net debt levels. To facilitate the management of these ratios, the Trust prepares annual budgets, which are updated depending on varying factors such as general market conditions and successful capital deployment. Currently, all ratios are within acceptable parameters. The annual budget is approved by the Board of Directors. The Trust's unitholders' capital is not subject to any external financial covenants.

There were no changes in the Trust's approach to capital management from the previous year.



($000s) September 30, 2009 December 31, 2008
----------------------------------------------------------------------------
Unitholders' equity 624,855 550,717
Long-term debt 420,000 500,000
Working capital (surplus) deficit(1) (9,013) (32,075)
----------------------------------------------------------------------------
1,035,842 1,018,642
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Current liabilities less current assets (includes unrealized hedging
asset of $14.0 million (2008 - $27.8 million))


12. Supplemental Cash Flow Information

Three Months Ended Nine Months Ended
September 30 September 30
($000) 2009 2008 2009 2008
----------------------------------------------------------------------------
Cash interest paid during the period 4,493 5,018 11,919 16,837
----------------------------------------------------------------------------
----------------------------------------------------------------------------


13. Contingencies and Commitments

Following is a summary of the Trust's commitments related to operating leases as at September 30, 2009. The Trust has no other contractual obligations or commitments as at September 30, 2009.



($000) September 30,
2009
----------------------------------------------------------------------------

2009 97
2010 1,036
2011 1,036
2012 1,036
2013 1,036
2014 1,036
----------------------------------------------------------------------------
5,277
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Contingent Liability

From time to time, Peyto is the subject of litigation arising out of its day-to-day operations. Damages claimed pursuant to such litigation, may be material or may be indeterminate and the outcome of such litigation may materially impact Peyto's financial position or results of operations in the period of settlement. While Peyto assesses the merits of each lawsuit and defends itself accordingly Peyto may be required to incur significant expenses or devote significant resources to defending itself against such litigation. These claims are not currently expected to have a material impact on Peyto's financial position or results of operations.



Peyto Exploration & Development Corp. Information

Officers

Darren Gee Glenn Booth
President and Chief Executive Officer Vice-President, Land

Scott Robinson Stephen Chetner
Executive Vice-President and Chief Operating Officer Corporate Secretary

Kathy Turgeon
Vice-President, Finance and Chief Financial Officer


Directors
Don Gray, Chairman
Michael MacBean, Lead Independent Director
Rick Braund
Brian Davis
Darren Gee
Gregory Fletcher
Stephen Chetner

Auditors
Deloitte & Touche LLP

Solicitors
Burnet, Duckworth & Palmer LLP

Bankers
Bank of Montreal
Union Bank, Canada Branch
BNP Paribas (Canada)
Royal Bank of Canada
Alberta Treasury Branches
Societe Generale (Canada Branch)
HSBC Bank Canada
Canadian Western Bank

Transfer Agent
Valiant Trust Company

Head Office
1500, 250 - 2(nd) Street SW Calgary, AB
T2P 0C1
Phone: 403.261.6081 Fax: 403.451.4100 Web: www.peyto.com

Stock Listing Symbol: PEY.un
Toronto Stock Exchange


Contact Information

  • Peyto Energy Trust
    Darren Gee
    President & CEO
    (403) 261-6081
    (403) 451-4100 (FAX)
    www.peyto.com