Peyto Energy Trust
TSX : PEY.UN

November 09, 2010 08:31 ET

Peyto Energy Trust Announces Strong Growth for the Third Quarter 2010

CALGARY, ALBERTA--(Marketwire - Nov. 9, 2010) - Peyto Energy Trust ("Peyto" or the "Trust") (TSX:PEY.UN) is pleased to present the operating and financial results for the third quarter of the 2010 fiscal year. The Trust grew production 34% year over year or 25% per unit since Q3 2009 while generating third quarter operating margins of 74%(1) and profit margins of 43%(2). Third quarter 2010 highlights were as follows:

  • Production grew from 107 MMcfe/d (17,792 boe/d) in Q3 2009 to 143 MMcfe/d (23,775 boe/d) in Q3 2010, as a result of the continued development of Peyto's Deep Basin tight gas plays. This equates to a 25% increase per unit, a 34% increase on an absolute basis, and a 36% increase in production per unit, debt adjusted (3).
  • Funds from operations ("FFO") increased 25% from $45.3 million in Q3 2009 to $56.7 million in Q3 2010 in response to the increased production volumes despite a 6% drop in realized commodity prices from $6.20/mcfe to $5.83/mcfe respectively (including hedging gains). FFO per unit were up 21% to $0.47/unit.
  • Industry leading operating costs were reduced 17% to $0.34/mcfe ($2.04/boe) from Q3 2009 or $0.48/mcfe ($2.86/boe) including transportation. Corporate netbacks were 6% lower at $4.32/Mcfe ($25.94/boe), or 74% of revenue.
  • Capital expenditures of $64.1 million (net of $2.0 million in Drilling Royalty Credits) were invested in the quarter, up 123% from $28.7 million in Q3 2009. A total of 9 net wells were drilled during the quarter.
  • Earnings of $32.6 million ($0.27/unit) were generated in the quarter and distributions to unitholders were $43.9 million ($0.36/unit).

Third Quarter 2010 in Review

In the third quarter, Peyto continued to focus on maintaining its low cost structure. This unique cost structure ensures the Trust delivers high netbacks, even at the bottom of the natural gas price cycle, and allows Peyto to develop its assets when demand for services are low and input costs are reasonable. Peyto takes advantage of this counter cyclical investment approach with the confidence that strong returns are being generated, even at current gas prices. The Trust had a very active third quarter, investing 123% more than Q3 2009, as last year's successful horizontal pilot programs evolved into multi-well development programs. By the end of the third quarter, the 2010 capital program was responsible for approximately 58 MMcfe/d (9,700 boe/d) of new production or 38% of total production. Operating costs continued to decline, with higher production from new wells increasing facility utilizations. Peyto's facility and pipeline infrastructure was expanded in the quarter, to accommodate the increased production volumes. Peyto also increased its core area prospect inventory with the purchase of new Deep Basin lands, bringing total undeveloped land purchases for 2010 to 50,400 net acres (79 sections). Alberta spot natural gas price averaged $3.36/GJ in the third quarter, up 20% from $2.79/GJ in the third quarter 2009 but lower than the $3.69/GJ experienced last quarter. Peyto's high heat content and liquids rich, natural gas production garnered $4.85/Mcfe before hedging and $5.83/Mcfe after hedging. Continued strong financial and operating performance resulted in an annualized 19% Return on Equity (ROE) and 11% Return on Capital Employed (ROCE).

  1. Operating Margin is defined as Funds from Operations divided by Revenue before Royalties but including realized hedging gains (losses).
  2. Profit Margin is defined as Net Earnings for the quarter divided by Revenue before Royalties but including realized hedging gains (losses).
  3. Per unit results are adjusted for changes in net debt and equity. Net debt is converted to equity using a Sept. 30 unit price of $15.54 for 2010 and $10.69 for 2009.

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.

  3 Months Ended September 30   %   9 Months Ended September 30   %  
  2010   2009   Change   2010   2009   Change  
Operations                        
Production                        
  Natural gas (mcf/d) 122,717   89,259   37 % 113,093   91,791   23 %
  Oil & NGLs (bbl/d) 3,322   2,916   14 % 3,373   2,962   14 %
  Thousand cubic feet equivalent (mcfe/d @ 1:6) 142,651   106,755   34 % 133,328   109,565   22 %
  Barrels of oil equivalent (boe/d @ 6:1) 23,775   17,792   34 % 22,221   18,261   22 %
                         
Product prices                        
  Natural gas ($/mcf) 5.16   5.74   (10 )% 5.55   6.54   (15 )%
  Oil & NGLs ($/bbl) 59.66   51.06   17 % 64.70   46.30   40 %
  Operating expenses ($/mcfe) 0.34   0.41   (17 )% 0.37   0.43   (14 )%
  Transportation ($/mcfe) 0.14   0.11   27 % 0.13   0.11   18 %
  Field netback ($/mcfe) 4.83   5.22   (7 )% 5.13   5.58   (8 )%
  General & administrative expenses ($/mcfe) 0.12   0.15   (20 )% 0.12   0.19   (37 )%
  Interest expense ($/mcfe) 0.39   0.46   (15 )% 0.40   0.40   -  
Financial ($000, except per unit)                        
Revenue 76,450   60,860   26 % 230,794   201,299   15 %
Royalties 6,800   4,507   51 % 25,694   18,214   41 %
Funds from operations 56,743   45,263   25 % 167,717   149,397   12 %
Funds from operations per unit 0.47   0.39   21 % 1.41   1.37   3 %
Total distributions 43,875   41,371   6 % 128,969   121,891   6 %
Total distributions per unit 0.36   0.36   -   1.08   1.12   (4 )%
  Payout ratio 77   91   (15 )% 77   82   (6 )%
Earnings 32,567   26,785   22 % 94,138   119,547   (21 )%
Earnings per diluted unit 0.27   0.23   17 % 0.79   1.10   (28 )%
Capital expenditures 64,123   28,725   123 % 150,923   46,432   225 %
Weighted average trust units outstanding 121,765,712   114,920,194   6 % 118,803,946   109,085,029   9 %
As at September 30                        
Net Debt             457,959   423,964   8 %
Unitholders' equity             699,576   623,883   12 %
Total assets             1,377,935   1,240,770   11 %
                         
                         
  3 Months Ended September 30   9 Months Ended September 30  
($000) 2010   2009   2010   2009  
Cash flows from operating activities 48,681   49,827   156,986   152,121  
Change in non-cash working capital 5,129   (5,726 ) (704 ) (4,500 )
Change in provision for performance based compensation 2,933   1,162   11,435   1,776  
Funds from operations 56,743   45,263   167,717   149,397  
Funds from operations per unit 0.47   0.39   1.41   1.37  

(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.

Capital Expenditures

Peyto had a very active third quarter, investing $64.1 million (net of $2.0 million in Drilling Royalty Credits) in the ongoing development of its Deep Basin core areas. The Trust spent $56.7 million on new drilling, completions and well tie-ins, $4.6 million on plant expansions and $4.8 million on the purchase of new opportunities in the form of undeveloped land.

During the quarter, 10 gross (9 net) wells were drilled, including 9 horizontal wells and one multi-zone vertical well. In total, 16 gross (15 net) zones were completed and 17 gross (16 net) zones brought on stream.

The Peyto Nosehill gas plant underwent an expansion in the quarter, increasing the capacity from 30 to 50 MMcf/d. As well, a 20 km, 8" pipeline was constructed to connect new Obed volumes to the Wildhay gas plant.

The Trust was active in the quarter purchasing new crown mineral leases with 28,000 net acres (43.75 sections) of new lands acquired at an average cost of $144/acre. Drilling locations have been identified on these new lands, which are all adjacent to Peyto's core areas, and will benefit from the Trust's existing facility infrastructure. So far in 2010, total land purchases equate to a 30% increase in prospective undeveloped land.

Financial Results

In the third quarter 2010, the Trust realized natural gas prices of $4.02/mcf, from average Alberta gas prices of $3.47/GJ, while realizing $59.66/bbl for its natural gas liquids blend of condensate, propane and butane. This liquids price represents 80% of the average Edmonton light oil price of $74.46/bbl. The natural gas and liquids streams, split 86% and 14% of production respectively, combined for an unhedged revenue stream of $4.85/mcfe or $29.10/boe. Realized hedging gains improved revenues by $0.98/mcfe ($5.88/boe). Total cash costs of $1.51/mcfe, made up of $0.52/mcfe for royalties, $0.34/mcfe for operating costs, $0.14/mcfe for transportation costs, $0.12/mcfe for G&A, and $0.39/mcfe for interest, reduced the realized revenue to $4.32/mcfe or $25.94/boe. This cash netback of $4.32/mcfe equates to 74% of revenue.

DD&A of $1.69/mcfe, as well as a provision for future performance based compensation and future income tax, reduced funds from operations to yield earnings of $2.48/mcfe or a 43% profit margin.

Unitholder participation in Peyto's Distribution Re-Investment Plan ("DRIP") and Optional Trust Unit Purchase Plan ("OTUPP") resulted in the issuance of 1,035,384 units at an average price of $14.01 for net proceeds of $14.5 million during the third quarter.

Marketing

Natural gas prices in the third quarter 2010 continued to reflect the abundance of supply in North America even with increased weather related demand. Drilling activity for natural gas remained high despite these lower prices which further increased this over-supplied situation. As a result, Canadian natural gas prices remained at historical low levels averaging $3.36/GJ for daily AECO spot price. Meanwhile, US natural gas prices declined 20% throughout the quarter and are now approaching Canadian gas price levels. Peyto's strategy of forward natural gas sales resulted in a realized Q3 2010 hedging gain of $12.9 million. This compares with a gain of $11.4 million in the second quarter 2010 and a $20.0 million gain in Q3 2009.

As at September 30, 2010, the Trust had committed to the future sale of 23,280,000 gigajoules (GJ) of natural gas at an average price of $5.07/GJ or $5.93/mcf. Had these contracts been closed on September 30, 2010, the Trust would have realized a gain in the amount of $41.5 million.

Activity Update

At this time, production has already reached the year-end target of 28,000 boe/d as new horizontal well completions continue to meet or exceed expectations. Peyto is currently running 8 drilling rigs and expects to drill another 12 gross (11.5 net) horizontal wells this year. In addition to the 4 gross (4 net) horizontal wells that are currently being completed and tied in, the majority of these 12 new wells are also expected to be completed and on-stream before the end of the fourth quarter.

During the fourth quarter, another compressor will be installed at each of Peyto's Nosehill and Wildhay gas plants, increasing processing capacity to 60 MMcf/d and 30 MMcf/d respectively. By the end of 2010, Peyto will have added over 70 MMcf/d of processing capacity for a total capital investment of $15 million. The combination of this facility work and the new well activity is expected to increase Peyto's net production beyond 30,000 boe/d by year-end.

Corporate Conversion

On November 8, 2010, an Information Circular was mailed to unitholders of record, as at November 5, 2010, outlining the process for conversion of the Trust to corporate form. The conversion will be effected pursuant to a unitholder and court approved Plan of Arrangement, with a unitholder meeting planned for December 8, 2010. The effective date of the conversion is expected to be December 31, 2010. For the remainder of 2010, the Trust plans on maintaining distributions at $0.12/unit/month, at which point distributions will be terminated and a $0.06/month dividend will be introduced. This dividend level is confirmed for the first quarter of 2011 and future dividend levels will be set by the Board of Directors of Peyto in early 2011.

Upon conversion to a corporation, The Board of Directors of Peyto has decided not to offer a Dividend Re-Investment Plan. This decision is predicated on the fact that a significant portion of Peyto unitholders, who are non-Canadian unitholders, cannot participate.

Outlook

Peyto is pleased to announce the appointment of David Thomas to the position of Vice-President, Exploration. Dave has been a senior exploration geologist with Peyto since 2005 and continues to bring a wealth of Deep Basin expertise to Peyto's ongoing exploration and development programs.

Peyto has already reached its previously announced year end production target of 28,000 boe/d and is now on track to exit 2010 at or above 30,000 boe/d. The team is refining the details of the 2011 capital program which is expected to be between $250 to $275 million. This program will target a blend of horizontal multi-stage frac well development amongst existing successful play types and new tests of formations across Peyto's core areas. The team's hard work and focus on cost control allows Peyto to continue to concentrate on low cost, high netback, liquids rich, natural gas prospects. As always, Peyto will continue to innovate and expand its opportunity base beyond the existing seven year inventory.

Conference Call and Webcast

A conference call will be held with the senior management of Peyto to answer questions with respect to the 2010 third quarter financial results on Wednesday, November 10th, 2010, at 9:00 a.m. Mountain Standard Time (MST), or 11:00 a.m. Eastern Standard Time (EST). To participate, please call 1- 416-340-2216 (Toronto area) or 1- 866-226-1792 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 6474758. The replay will be available at 11:00 a.m. MST, 1:00 p.m. EST Wednesday, November 10th, 2010 until midnight EST on Wednesday, November 17th, 2010. The conference call can also be accessed through the internet at http://events.digitalmedia.telus.com/peyto/111010/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

Management's Discussion and Analysis of this third quarter report is available on the Peyto website at http://www.peyto.com/news/Q32010MDandA.pdf. A complete copy of the third quarter report to Unitholders, including the Management's Discussion and Analysis, and financial statements and related notes is also available at www.peyto.com and will be filed at SEDAR, www.sedar.com , at a later date.

Unitholders are encouraged to follow the progress of Peyto's 2010 capital program with monthly president's reports and updated presentations on the Peyto website.

Darren Gee
President and CEO
November 9, 2010

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,  
  2010   2009  
         
Assets        
Current        
Cash 6,628   -  
Accounts receivable (Note 3 and 10) 56,249   58,305  
Due from private placement (Note 6) -   2,728  
Financial derivative instruments (Note 10) 35,399   8,683  
Prepaid expenses and deposits 4,366   3,787  
  102,642   73,503  
         
Financial derivative instruments (Note 10) 6,115   1,253  
Prepaid capital 3,362   955  
Property, plant and equipment (Note 4) 1,265,816   1,178,402  
  1,275,293   1,180,610  
         
  1,377,935   1,254,113  
         
Liabilities and Unitholders' Equity        
Current        
Accounts payable and accrued liabilities 55,546   55,890  
Distributions payable 14,656   13,790  
Provision for future performance based compensation 11,486   2,001  
  81,688   71,681  
         
Long-term debt (Note 5) 455,000   435,000  
Provision for future performance based compensation 2,990   1,041  
Asset retirement obligations 11,449   10,487  
Future income taxes 127,232   123,421  
  596,671   569,949  
         
Unitholders' equity        
Unitholders' capital (Note 6) 594,437   500,407  
Units to be issued (Note 6) 6,064   2,728  
  600,501   503,135  
Accumulated earnings (Note 7) 64,919   99,749  
Accumulated other comprehensive income 34,156   9,599  
  99,075   109,348  
  699,576   612,483  
         
  1,377,935   1,254,113  

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 Sept 30   Nine Months Ended Sept 30  
  2010   2009   2010   2009  
Revenue                
Oil and gas sales 63,578   40,841   200,669   150,390  
Realized gain on hedges 12,872   20,019   30,124   50,909  
Royalties (6,800 ) (4,507 ) (25,693 ) (18,214 )
Petroleum and natural gas sales, net 69,650   56,353   205,100   183,085  
                 
Expenses                
Operating (Note 8) 4,462   3,982   13,634   12,739  
Transportation 1,785   1,097   4,798   3,370  
General and administrative(Note 9) 1,524   1,518   4,434   5,660  
Future performance based compensation provision 2,933   1,162   11,435   1,776  
Interest on long term debt 5,136   4,493   14,517   11,919  
Depletion, depreciation and accretion (Note 4) 22,230   17,966   64,549   54,261  
  38,070   30,218   113,367   89,725  
Earnings before taxes 31,580   26,135   91,733   93,360  
                 
Taxes                
Future income tax recovery 987   841   2,405   26,378  
                 
Earnings for the period 32,567   26,976   94,138   119,738  
                 
Earnings per unit (Note 6)                
Basic and diluted 0.27   0.24   0.79   1.10  

See accompanying notes

Peyto Energy Trust

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

  Three Months Ended Sept 30   Nine Months Ended Sept 30  
  2010   2009   2010   2009  
Earnings for the period 32,567   26,976   94,138   119,738  
Other comprehensive income                
Change in unrealized gain (loss) on cash flow hedges 18,104   (2,497 ) 54,681   37,025  
Realized (gain) loss on cash flow hedges (12,872 ) (20,019 ) (30,124 ) (50,909 )
Comprehensive income 37,799   4,460   118,695   105,854  

See accompanying notes

Peyto Energy Trust

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

  Three Months Ended Sept 30   Nine Months Ended Sept 30  
  2010   2009   2010   2009  
                 
Accumulated earnings, beginning of period 76,227   122,480   99,749   110,238  
Net earnings for the period 32,567   26,976   94,138   119,738  
Distributions (Note 7) (43,875 ) (41,371 ) (128,968 ) (121,891 )
Accumulated earnings, end of period 64,919   108,085   64,919   108,085  
                 
Accumulated other comprehensive income, beginning of period 28,924   38,878   9,599   30,246  
Other comprehensive income (loss) 5,232   (22,516 ) 24,557   (13,884 )
Accumulated other comprehensive income, end of period 34,156   16,362   34,156   16,362  

See accompanying notes

Peyto Energy Trust

Consolidated Statements of Cash Flows
($000)
(unaudited)

  Three Months Ended Sept 30   Nine Months Ended Sept 30  
  2010   2009   2010   2009  
Cash provided by (used in)                
Operating Activities                
Earnings for the period 32,567   26,976   94,138   119,738  
Items not requiring cash:                
  Future income tax recovery (987 ) (841 ) (2,405 ) (26,378 )
  Depletion, depreciation and accretion 22,230   17,966   64,549   54,261  
Change in non-cash working capital related to operating activities (5,129 ) 5,726   704   4,500  
  48,681   49,827   156,986   152,121  
Financing Activities                
Issuance of trust units (Note 6) 11,245   -   93,396   94,500  
Issuance costs (Note 6) -   (17 ) (3,968 ) (5,106 )
Cash distribution paid (net of DRIP) (40,609 ) (41,371 ) (121,836 ) (121,891 )
Increase (decrease) in bank debt 25,000   (40,000 ) 20,000   (80,000 )
Change in non-cash working capital related to financing activities 771   -   3,594   (2,097 )
  (3,593 ) (81,388 ) (8,814 ) (114,594 )
Investing Activities                
Additions to property, plant and equipment (67,485 ) (28,725 ) (153,409 ) (46,432 )
Change in non-cash working capital related to investing activities 19,750   18,722   11,865   8,905  
  (47,735 ) (10,003 ) (141,544 ) (37,527 )
Net increase (decrease) in cash (2,647 ) (41,564 ) 6,628   -  
Cash, beginning of period 9,275   41,564   -   -  
Cash, end of period 6,628   -   6,628   -  
                 
See accompanying notes                

Peyto Energy Trust

Notes to Consolidated Financial Statements
 (unaudited)

September 30, 2010 and 2009

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 2009 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

Pending Accounting Pronouncements

In January 2006, the CICA Accounting Standards Board ("ASCB") adopted a strategic plan for the direction of accounting standards in Canada. As part of that plan, accounting standards in Canada for public companies are expected to converge with International Financial Reporting Standards ("IFRS") by 2011.

3. Accounts Receivable

($000) September 30, 2010   December 31, 2009  
Accounts receivable – general 49,094   51,150  
Accounts receivable – income taxes 7,155   7,155  
  56,249   58,305  

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 $7.2 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 of the CRA officer are on-going. If the matter cannot be settled, it is expected to go to trial. 

4. Property, Plant and Equipment

($000) September 30, 2010   December 31, 2009  
         
Property, plant and equipment 1,776,070   1,624,655  
Accumulated depletion and depreciation (510,254 ) (446,253 )
  1,265,816   1,178,402  

At September 30, 2010 costs of $29.6 million (December 31, 2009 - $26.6 million) related to undeveloped land have been excluded from the depletion and depreciation calculation. 

5. Long-Term Debt

The Trust has a syndicated $625 million extendible revolving credit facility with a stated term date of April 30, 2011. The facility is made up of a $20 million working capital sub-tranche and a $605 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 1.25% to 2.75% 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, 2010 was 4.8% and 4.6% respectively (2009 – 3.1% and 3.0% 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) -   (4,326 )
Balance, December 31, 2009 114,920,194   500,407  
Trust units issued by private placement 196,420   2,728  
Trust units issued 5,566,000   74,863  
Trust unit issuance costs (net of tax) -   (3,163 )
Trust units issued pursuant to DRIP 461,516   6,250  
Trust units issued pursuant to OTUPP 992,548   13,352  
Balance, September 30, 2010 122,136,678   594,437  

Units Issued
On April 27, 2010, Peyto closed an offering of 5,566,000 trust units at a price of $13.45 per trust unit, receiving proceeds of $71.7 million (net of issuance costs).

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 $90.2 million (net of issuance costs).

On December 31, 2009 the Trust completed a private placement of 196,420 trust units to employees and consultants for net proceeds of $2.7 million ($13.89 per unit). These trust units were issued on January 6, 2010. 

Peyto reinstated its amended distribution reinvestment and optional trust unit purchase plan (the "Amended DRIP Plan") effective with the January 2010 distribution whereby eligible unitholders may elect to reinvest their monthly cash distributions in additional trust units at a 5% discount to market price. The DRIP plan incorporates an Optional Trust Unit Purchase Plan ("OTUPP") which provides unitholders enrolled in the DRIP with the opportunity to purchase additional trust units from treasury using the same pricing as the DRIP. 

Units to be Issued
Subsequent to September 30, 2010, 444,558 trust units (64,677 pursuant to the DRIP and 379,881 pursuant to the OTUPP) were issued for net proceeds of $6.1 million. Subsequent to the issuance of these units, 122,581,236 trust units were outstanding. 

Per Unit Amounts
Earnings per unit have been calculated based upon the weighted average number of units outstanding for three months ended September 30, 2010 of 121,765,712 (2009 – 114,920,194) and for the nine months ended September 30, 2010 of 118,803,946 (2009 – 109,085,029). There are no dilutive instruments outstanding.

7. Accumulated Distributions

The Trust declared total distributions to the unitholders in the aggregate amount of $43.9 million in the three months ended September 30, 2010 (2009 – total $41.4 million) and $129.0 million for the nine months ended September 30, 2010 (2009 - total $121.9 million) in accordance with the following schedule:

Production Period   Record Date   Distribution Date   Per Unit (1)
January 2010   January 31, 2010   February 15, 2010   $0.12
February 2010   February 28, 2010   March 15, 2010   $0.12
March 2010   March 31, 2010   April 15, 2010   $0.12
April 2010   April 30, 2010   May 14, 2010   $0.12
May 2010   May 31, 2010   June 15, 2010   $0.12
June 2010   June 30, 2010   July 15, 2010   $0.12
July 2010   July 31, 2010   August 13, 2010   $0.12
August 2010   August 31, 2010   September 15, 2010   $0.12
September 2010   September 30, 2010   October 31, 2010   $0.12

(1) Distributions per trust unit are the amounts declared monthly to unitholders.

Accumulated Earnings and Distributions

($000) September 30, 2010   December 31, 2009  
Accumulated earnings, beginning of period 1,072,209   919,435  
Earnings for the period 94,138   152,774  
Total accumulated earnings 1,166,347   1,072,209  
Total accumulated distributions (1,101,428 ) (972,460 )
Accumulated earnings, end of period 64,919   99,749  

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 Sept 30   Nine Months Ended Sept 30  
($000) 2010   2009   2010   2009  
Field expenses 7,055   6,839   21,565   20,962  
Processing and gathering income (2,593 ) (2,857 ) (7,931 ) (8,223 )
Total operating costs 4,462   3,982   13,634   12,739  

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 Sept 30   Nine Months Ended Sept 30  
($000) 2010   2009   2010   2009  
General and administrative expenses 2,507   2,343   7,243   7,351  
Overhead recoveries (983 ) (825 ) (2,809 ) (1,691 )
Net general and administrative expenses 1,524   1,518   4,434   5,660  

10. Financial Instruments and Risk Management

Financial Instrument Classification and Measurement
Financial instruments of the Trust carried on the Consolidated Balance Sheet are carried at amortized cost with the exception of cash and financial derivative instruments, specifically fixed price contracts, which are carried at fair value. There are no significant differences between the carrying value of financial instruments and their estimated fair values as at September 30, 2010.

The fair value of the Trust's cash and financial derivative instruments are quoted in active markets. The Trust classifies the fair value of these transactions according to the following hierarchy.

  • Level 1 – quoted prices in active markets for identical financial instruments.
  • Level 2 – quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets.
  • Level 3 – valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable.

The Trust's cash and financial derivative instruments have been assessed on the fair value hierarchy described above and classified as Level 1. 

Fair Values of Financial Assets and Liabilities
The Trust's financial instruments include cash, accounts receivable, financial derivative instruments, due from private placement, current liabilities (excluding future income tax), provision for future performance based compensation and long term debt. At September 30, 2010, the carrying value of cash and financial derivative instruments are carried at fair value. Accounts receivable, due from private placement, current liabilities (excluding future income tax) and provision for future performance based compensation approximate their fair value due to their short term nature. The carrying value of the long term debt approximates its fair value due to the floating rate of interest charged under the credit facility.

Market Risk
Market risk is the risk that changes in market prices will affect the Trust's earnings or the value of its financial instruments. Market risk is comprised of commodity price risk, currency risk and interest rate risk. The objective of market risk management is to manage and control 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 companies the Trust considers to be 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, 2010 are as follows:

Description
($000 except per GJ amounts)
Notional (1)   Term Effective
Rate
Fair
Value
Level
Asset as at
September
30, 2010
Asset as at
December
31, 2009
Natural gas financial swaps - AECO 23.28GJ (2 ) 2010-2012 $5.07/GJ Level 1 41,514 $9,936
(1) Notional values as at September 30, 2010 (2) Millions of gigajoules
             
Natural Gas
Period Hedged
Type   Daily
Volume
  Price
(CAD)
 
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 , 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  
April 1, 2010 to October 31, 2010 Fixed Price   5,000 GJ   $5.50/GJ  
April 1, 2010 to October 31, 2010 Fixed Price   5,000 GJ   $4.50/GJ  
April 1, 2010 to March 31, 2011 Fixed Price   5,000 GJ   $5.28/GJ  
April 1, 2010 to March 31, 2011 Fixed Price   5,000 GJ   $5.29/GJ  
April 1, 2010 to March 31, 2011 Fixed Price   5,000 GJ   $5.555/GJ  
April 1, 2010 to March 31, 2011 Fixed Price   5,000 GJ   $5.70/GJ  
April 1, 2010 to March 31, 2011 Fixed Price   5,000 GJ   $4.55/GJ  
April 1, 2010 to March 31, 2012 Fixed Price   5,000 GJ   $5.67/GJ  
April 1, 2010 to March 31, 2012 Fixed Price   5,000 GJ   $5.82/GJ  
July 1, 2010 to October 31, 2010 Fixed Price   5,000 GJ   $4.03/GJ  
July 1, 2010 to October 31, 2010 Fixed Price   5,000 GJ   $4.20/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  
April 1 , 2011 to March 31, 2012 Fixed Price   5,000 GJ   $6.20/GJ  
April 1 , 2011 to March 31, 2012 Fixed Price   5,000 GJ   $5.00/GJ  
April 1 , 2011 to March 31, 2012 Fixed Price   5,000 GJ   $5.12/GJ  
November 1, 2011 to March 31, 2012 Fixed Price   5,000 GJ   $4.50/GJ  

As at September 30, 2010, the Trust had committed to the future sale of 23,280,000 gigajoules (GJ) of natural gas at an average price of $5.07 per GJ or $5.93 per mcf. Had these contracts been closed on September 30, 2010, the Trust would have realized a gain in the amount of $41.5 million. If the AECO gas price on September 30, 2010 were to increase by $1/GJ, the unrealized gain on these closed contracts would change by approximately $23.3 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. 

Subsequent to September 30, 2010 the Trust entered into the following contracts:

Natural Gas
Period Hedged
Type   Daily
Volume
  Price
(CAD)
 
April 1, 2011 to October 31, 2012 Fixed Price   5,000 GJ   $4.05/GJ  

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, 2010 would decrease by $1.1 million and $3.2 million respectively. An opposite change in interest rates will result in an opposite impact on earnings. 

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 individually significant accounts receivable for the period ended September 30, 2010, approximately 13% was due from one company (September 30, 2009 – 10%, one company). Of the Trust's revenue for the nine months ended September 30, 2010, approximately 94% was received from six companies (23%, 19%, 16%, 13%, 12% and 11%) (September 30, 2009 – 86%, four companies (31%, 25%, 19% and 11%)). 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, 2010, 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, 2010:

($000s) <1 Year   1-2 Years   2-5 Years   Thereafter  
Accounts payable and accrued liabilities 55,546              
Distributions payable 14,656              
Provision for future performance based compensation 11,486   2,990          
Long-term debt(1)     455,000          

 (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 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.

($000) September 30, 2010   December 31, 2009  
Unitholders' equity 699,576   612,483  
Long-term debt 455,000   435,000  
Working capital (surplus) deficit (1) (20,954 ) (1,822 )
  1,133,622   1,045,661  

(1)Current liabilities less current assets (includes unrealized hedging asset of $35.4 million (2009 – $8.7 million)
12. Supplemental Cash Flow Information

  Three Months Ended Sept 30   Nine Months Ended Sept 30  
($000) 2010   2009   2010   2009  
Cash interest paid during the period 5,136   4,493   14,517   11,919  

13. Contingencies and Commitments

Following is a summary of the Trust's commitments related to operating leases as at September 30, 2010. The Trust has no other contractual obligations or commitments as at September 30, 2010.

($000) September 30, 2010  
     
2010       260  
2011   1,043  
2012   1,043  
2013   1,043  
2014  1,043  
    4,432  

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. 

14. Subsequent Events

On November 1, 2010, the Board of Directors of Peyto Energy Administration Corp. unanimously resolved to approve the conversion of the Trust to a corporation effective December 31, 2010, pending Unitholder approval on December 8, 2010.

Peyto Exploration & Development Corp. Information

Officers    
  Darren Gee President and Chief Executive Officer   Glenn Booth Vice-President, Land
     
  Scott Robinson Executive Vice-President and Chief Operating Officer   David Thomas Vice-President, Exploration
     
  Kathy Turgeon Vice-President, Finance and Chief Financial Officer   Stephen Chetner Corporate Secretary
     
Directors    
  Don Gray, Chairman    
  Rick Braund    
  Stephen Chetner    
  Brian Davis    
  Michael MacBean, Lead Independent Director    
  Darren Gee    
  Gregory Fletcher    
  Scott Robinson    
     
Auditors    
  Deloitte & Touche LLP    
     
Solicitors    
  Burnet, Duckworth & Palmer LLP    
     
Bankers    
  Bank of Montreal    
  Union Bank, Canada Branch    
  BNP Paribas (Canada)    
  Royal Bank of Canada    
  Canadian Imperial Bank of Commerce    
  Alberta Treasury Branches    
  Société Générale (Canada Branch)    
  HSBC Bank Canada    
  Canadian Western Bank    
     
Transfer Agent    
  Valiant Trust Company    
     
Head Office    
  1500, 250 – 2nd 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 and CEO
    403.261.6081
    403.451.4100 (FAX)
    www.peyto.com