The Globe and Mail

Go to the Globe and Mail homepage

Jump to main navigationJump to main content

Press release from Marketwire

Peyto Energy Trust Announces Second Quarter 2010 Results and Continued Production Growth

Wednesday, August 11, 2010

Peyto Energy Trust Announces Second Quarter 2010 Results and Continued Production Growth16:13 EDT Wednesday, August 11, 2010CALGARY, ALBERTA--(Marketwire - Aug. 11, 2010) - Peyto Energy Trust ("Peyto" or the "Trust") (TSX:PEY.UN) is pleased to present the operating and financial results for the second quarter of the 2010 fiscal year. The Trust generated operating margins of 70%(1) and profit margins of 33%(2) in the quarter, along with 23% growth in production. Second quarter 2010 highlights were as follows:- Production grew from 108 MMcfe/d (17,982 boe/d) in Q2 2009 to 133 MMcfe/d (22,202 boe/d) in Q2 2010, as a result of continued horizontal drilling success in Peyto's Deep Basin tight gas plays. This equates to a 23% year over year increase or a 29% increase in production per unit, debt adjusted (3).- Funds from operations ("FFO") increased 15% from $45.5 million in Q2 2009 to $52.4 million in Q2 2010 resulting from the increased production volumes and a 51% increase in oil and NGL prices. FFO per unit were up 2% to $0.44/unit reflecting an increase in the number of trust units outstanding.- Operating costs were reduced 12% to $0.38/mcfe ($2.28/boe) while transportation costs increased 18% to $0.13/mcfe from Q2 2009. Corporate netbacks of $4.32/Mcfe ($25.94/boe) were 70% of revenue.- Capital of $37.4 million (net of $1.5 million in Drilling Royalty Credits) was invested in the quarter, up significantly from $4.7 million in Q2 2009. A total of 7 net horizontal wells were drilled during the quarter.- Earnings of $24.7 million ($0.21/unit) were generated in the quarter and $43.6 million ($0.36/unit) was distributed to unitholders.Second Quarter 2010 in ReviewPeyto embarked on its expanded capital program in the second quarter, utilizing 5 drilling rigs post breakup to continue development of its Cardium, Notikewin and Wilrich Deep Basin tight gas plays. All 5 rigs are capable of drilling the long horizontal wells required in the application of horizontal multi-stage fracture technology. By the end of the second quarter, the 2010 drilling program was responsible for approximately 30 mmcfe/d (5,000 boe/d) or 23% of total production. Operating costs per unit were lower as increased production volumes improved overall facility utilization and warmer temperatures resulted in reduced methanol consumption. A turnaround of the Oldman Gas Plant was completed in June, which temporarily shut in a portion of production, but it was conducted at a time when natural gas prices were at seasonal lows. Alberta spot natural gas price averaged $3.69/GJ in the second quarter, down from $4.70/GJ in the previous quarter but higher than the $3.27/GJ experienced last year. Peyto's production, with its high heat content natural gas and liquids components, garnered $5.20/mcfe before hedging and $6.14/mcfe after hedging. Continued strong financial and operating performance resulted in a 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 the June 30 unit price of $14.57 for 2010 and $9.37 for 2009. Natural gas volumes recorded in thousand cubic feet (mcf) are converted to barrels of oil equivalent (boe) using the ratio of six (6) thousand cubic feet to one (1) barrel of oil (bbl). Natural gas liquids and oil volumes in barrel of oil (bbl) are converted to thousand cubic feet equivalent (mcfe) using a ratio of one (1) barrel of oil to six (6) thousand cubic feet. This could be misleading if used in isolation as it is based on an energy equivalency conversion method primarily applied at the burner tip and does not represent a value equivalency at the wellhead. ---------------------------------------------------------------------------- Three Months ended June 30 % 2010 2009 Change ---------------------------------------------------------------------------- Operations Production Natural gas (mcf/d) 112,422 90,191 25% Oil & NGLs (bbl/d) 3,465 2,950 17% Thousand cubic feet equivalent (mcfe/d @ 1:6) 133,211 107,892 23% Barrels of oil equivalent (boe/d @ 6:1) 22,202 17,982 23% Product prices Natural gas ($/mcf) 5.25 6.14 (14)% Oil & NGLs ($/bbl) 65.58 43.42 51% Operating expenses ($/mcfe) 0.38 0.43 (12)% Transportation ($/mcfe) 0.13 0.11 18% Field netback ($/mcfe) 4.82 5.23 (8)% General & administrative expenses ($/mcfe) 0.09 0.19 (53)% Interest expense ($/mcfe) 0.41 0.39 5% Financial ($000, except per unit) Revenue 74,370 62,016 20% Royalties 9,721 5,417 79% Funds from operations 52,415 45,527 15% Funds from operations per unit 0.44 0.43 2% Total distributions 43,622 39,211 11% Total distributions per unit 0.36 0.37 (3)% Payout ratio 83 86 (10)% Earnings 24,696 29,189 (15)% Earnings per diluted unit 0.21 0.28 (25)% Capital expenditures 37,439 4,671 701% Weighted average trust units outstanding 119,419,799 106,315,789 12% As at December 31 Net debt (before future compensation expense and unrealized hedging gains) Unitholders' equity Total assets ---------------------------------------------------------------------------- Six Months ended June 30 % 2010 2009 Change ---------------------------------------------------------------------------- Operations Production Natural gas (mcf/d) 108,202 93,078 16% Oil & NGLs (bbl/d) 3,398 2,986 14% Thousand cubic feet equivalent (mcfe/d @ 1:6) 128,589 110,993 16% Barrels of oil equivalent (boe/d @ 6:1) 21,432 18,499 16% Product prices Natural gas ($/mcf) 5.77 6.93 (17)% Oil & NGLs ($/bbl) 67.21 43.94 53% Operating expenses ($/mcfe) 0.39 0.44 (11)% Transportation ($/mcfe) 0.13 0.11 18% Field netback ($/mcfe) 5.30 5.76 (8)% General & administrative expenses ($/mcfe) 0.13 0.21 (38)% Interest expense ($/mcfe) 0.40 0.37 8% Financial ($000, except per unit) Revenue 154,344 140,439 10% Royalties 18,894 13,707 38% Funds from operations 110,974 104,134 7% Funds from operations per unit 0.95 0.98 (3)% Total distributions 85,093 80,520 6% Total distributions per unit 0.72 0.76 (53)% Payout ratio 77 77 8% Earnings 61,571 92,763 (34)% Earnings per diluted unit 0.53 0.87 (39)% Capital expenditures 86,800 17,707 390% Weighted average trust units outstanding 117,298,518 106,119,089 11% As at December 31 Net debt (before future compensation expense and unrealized hedging gains) 417,854 399,513 5% Unitholders' equity 691,141 661,003 5% Total assets 1,320,085 1,292,556 2% ---------------------------------------------------------------------------- Three Months ended Six Months ended June 30 June 30 ($000) 2010 2009 2010 2009 ---------------------------------------------------------------------------- Cash flows from operating activities 55,923 50,193 108,306 102,295 Change in non-cash working capital (9,876) (4,130) (5,833) 1,226 Change in provision for performance based compensation 6,368 (536) 8,501 614 ---------------------------------------------------------------------------- Funds from operations 52,415 45,527 110,974 104,134 ---------------------------------------------------------------------------- Funds from operations per unit 0.44 0.43 0.95 0.98 ---------------------------------------------------------------------------- (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 ExpendituresAs part of the expanded 2010 capital program, the Trust invested a total of $38.9 million in the second quarter of 2010 and recovered $1.5 million in drilling royalty credits for net capital spending of $37.4 million. Drilling and completions accounted for $28.4 million or 73% of the total before credits, with wellsite equipment, pipelines and facilities accounting for $10.3 million. Land and seismic accounted for $0.3 million.Peyto drilled 8 gross (7 net) horizontal wells in the quarter, while 7 gross (6.6 net) zones were completed and 5 gross (4.6 net) zones brought on stream.Financial ResultsRealized natural gas and liquids prices of $5.25/mcf and $65.58/bbl, respectively, combined with operating costs of $0.38/mcfe, transportation costs of $0.13/mcfe, royalties of $0.81/mcfe, and G&A and interest costs of $0.50/mcfe to yield a cash netback of $4.32/mcfe. This netback equates to a 70% operating margin. Total cash costs of $1.82/mcfe ($10.92/boe) were down 6% from the previous quarter but up 8% from Q2 2009 due to increased royalty and transportation costs.Depletion, depreciation and accretion, as well as a provision for future performance based compensation, and future income tax reduced the 70% operating margin to a 33% profit margin or earnings of $2.04/mcfe ($12.22/boe).A public equity issue of 5.566 million trust units at $13.45/unit was completed during the quarter. Proceeds were initially used to reduce net debt, from $467 million at the end of Q1 2010 to $418 million at the end of Q2 2010, and to partially fund the Trust's expanded capital program. Peyto's credit facility was also expanded in the quarter from $550 million to $625 million following the annual review of the Trust's reserve assets by its syndicate of bankers. Peyto maintained its financial flexibility with $207 million of available borrowing capacity at the end of Q2 2010. Net debt of $418 million represents 2.0 times the annualized second quarter funds from operations and 26% of the Proved Producing BT NPV10, as determined at Jan 1, 2010.Peyto reinstated its Amended Distribution Re-Investment Plan ("DRIP") in January 2010 which incorporated the Optional Trust Unit Purchase Plan ("OTUPP"). During the second quarter of 2010, an average of 4% of outstanding Trust units participated in the DRIP which resulted in the issuance 122,809 units at an average unit price of $13.40 for net proceeds of $1,645,390. There were 440,441 units also issued under the OTUPP at an average unit price of $12.79 for net proceeds of $5,633,544.MarketingAlthough Alberta natural gas prices in the second quarter of 2010 were lower than the first quarter, they did not continue to fall like they did during the same period of 2009. In fact, prices increased throughout the quarter following an increase in US NYMEX natural gas price. Peyto's marketing strategy continued to smooth out the commodity price volatility with natural gas forward sales that realized a second quarter 2010 hedging gain of $11.4 million or $1.11/mcf. This compares with a gain of $17.6 million in Q2 2009.Peyto has continued this practice of forward selling a portion of its production and as at June 30, 2010, the Trust had committed to the future sale of 28,055,000 GJ of natural gas at an average price of $5.52/GJ or $6.46/mcf (assuming historical heat content). Had these contracts been closed on June 30, 2010, the Trust would have realized a gain in the amount of $32.4 million. For this coming heating season (Nov. 2010 to Mar. 2011), Peyto has forward sold 55,000 GJ/d or approximately 47 mmcf/d of natural gas at an average price of $7.23/mcf. This volume equates to 45% of the Trusts second quarter 2010 net of royalty production.Activity UpdateThe 2010 capital program remains on track to deliver profitable production growth, with 5 drilling rigs expected to work continuously in Peyto's core areas until the end of the year. Whereas the second quarter investment of $37.4 million was restricted by spring breakup, it is anticipated that the Trust will invest twice that amount over each of the next two quarters. An expansion of the Nosehill gas plant, to be completed mid-September, will increase the processing capacity from 30 mmcf/d to 50 mmcf/d. It is anticipated that additional compression will be added before year end to further increase the capacity to 60 mmcf/d. The Trust does not expect any material investments will be required this year at its other four operated gas plants as they have sufficient excess capacity to handle the growing production volumes.Since Peyto began developing its Deep Basin tight gas reservoirs with horizontal multi-stage fracture technology last fall, a total of 21 wells have been drilled, completed and placed on production (18.3 net to Peyto). Of these, eight are producing from the Cardium formation, five from the Notikewin formation and eight from the Falher/Wilrich formation. Initial test rates from these wells have varied from a low of 0.5 mmcfe/d to as high as 16 mmcfe/d. While there is much excitement surrounding these large initial rates, investors are cautioned that initial production rates are not a measure of profitability and therefore investment success. Of the 21 new wells, 16 have been on production for greater than one month with average first month controlled rates of 3.7 mmcfe/d. This average rate is approximately 5 times greater than the vertical well equivalent, while the average capital required is only 2.5 times. Although this vertical well production multiple is not expected to persist over the life of the horizontal well, and will diminish over time, it is responsible for accelerating the payout of the capital investment and improving the overall returns.As always, Peyto looks forward to communicating a comprehensive profitability analysis of the entire 2010 capital program, including the wells drilled horizontally, with the completion of the annual independent reserves evaluation.Corporate ConversionPeyto remains on track with plans for the conversion of the Trust into a corporate form effective December 31, 2010. The conversion will be effected pursuant to a unitholder and court approved plan of arrangement. Details of the conversion will be communicated in the coming months and a unitholder meeting is planned for December 8, 2010. For the remainder of 2010, the Trust plans on maintaining distributions at $0.12/unit/month.2010 OutlookWith significant production increases already realized, 2010 is turning out to be one of the most exciting years in Peyto's eleven year history. The Trust anticipates exceeding its previous production high of 24,000 boe/d sometime during the third quarter. By building assets counter cyclical to the rest of the natural gas industry in Canada, it is expected that cost savings and enhanced profitability will be achieved. Despite this exciting growth, the Trust remains cautious with respect to near term gas prices and continues to focus on maintaining its low cost advantage and financial flexibility. 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 at www.peyto.com.Conference Call and WebcastA conference call will be held with the senior management of Peyto to answer questions with respect to the 2010 second quarter and full year financial results on Thursday, August 12th, 2010, at 9:00 a.m. Mountain Daylight Time (MDT), or 11:00 a.m. Eastern Daylight Time (EDT). 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 6080762. The replay will be available at 11:00 a.m. MDT, 1:00 p.m. EDT Thursday, August 12th, 2010 until midnight EDT on Thursday, August 19th, 2010. The conference call can also be accessed through the internet at http://events.digitalmedia.telus.com/peyto/081210/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 AnalysisA copy of the second quarter report to Unitholders, including the Management's Discussion and Analysis, and financial statements and related notes is available at http://www.peyto.com/news/Q22010MDandA.pdf and will be filed at SEDAR, www.sedar.com , at a later date.Darren Gee, President and CEOAugust 11, 2010Certain 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) June 30, December 31, 2010 2009 ---------------------------------------------------------------------------- Assets Current Cash 9,276 - Accounts receivable (Note 3 and 10) 49,401 58,305 Due from private placement (Note 6) - 2,728 Financial derivative instruments (Note 10) 29,084 8,683 Prepaid expenses and deposits 5,635 3,787 ---------------------------------------------------------------------------- 93,396 73,503 ---------------------------------------------------------------------------- Financial derivative instruments (Note 10) 3,283 1,253 Prepaid capital - 955 Property, plant and equipment (Note 4) 1,223,607 1,178,402 ---------------------------------------------------------------------------- 1,226,890 1,180,610 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- 1,320,286 1,254,113 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Liabilities and Unitholders' Equity Current Accounts payable and accrued liabilities 38,281 55,890 Distributions payable 13,885 13,790 Provision for future performance based compensation 9,232 2,001 ---------------------------------------------------------------------------- 61,398 71,681 ---------------------------------------------------------------------------- Long-term debt (Note 5) 430,000 435,000 Provision for future performance based compensation 2,311 1,041 Asset retirement obligations 11,133 10,487 Future income taxes 124,303 123,421 ---------------------------------------------------------------------------- 567,747 569,949 ---------------------------------------------------------------------------- Unitholders' equity Unitholders' capital (Note 6) 584,996 500,407 Units to be issued (Note 6) 994 2,728 ---------------------------------------------------------------------------- 585,990 503,135 ---------------------------------------------------------------------------- Accumulated earnings (Note 7) 76,227 99,749 Accumulated other comprehensive income 28,924 9,599 ---------------------------------------------------------------------------- 105,151 109,348 ---------------------------------------------------------------------------- 691,141 612,483 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- 1,320,286 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 Six Months Ended June 30 June 30 2010 2009 2010 2009 ---------------------------------------------------------------------------- Revenue Oil and gas sales 63,002 44,386 137,091 109,549 Realized gain on hedges 11,368 17,629 17,253 30,890 Royalties (9,721) (5,417) (18,894) (13,707) ---------------------------------------------------------------------------- Petroleum and natural gas sales, net 64,649 56,598 135,450 126,732 ---------------------------------------------------------------------------- Expenses Operating (Note 8) 4,612 4,197 9,172 8,757 Transportation 1,578 1,094 3,013 2,272 General and administrative(Note 9) 1,075 1,904 2,911 4,142 Future performance based compensation provision 6,368 (536) 8,501 614 Interest on long term debt 4,969 3,876 9,381 7,426 Depletion, depreciation and accretion (Note 4) 21,906 17,718 42,319 36,295 ---------------------------------------------------------------------------- 40,508 28,253 75,297 59,506 ---------------------------------------------------------------------------- --------------------------------------------------------------------------- Earnings before taxes 24,141 28,345 60,153 67,226 ---------------------------------------------------------------------------- Taxes Future income tax recovery 555 844 1,418 25,537 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Earnings for the period 24,696 29,189 61,571 92,763 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Earnings per unit (Note 6) Basic and diluted 0.21 0.28 0.53 0.87 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- See accompanying notes Peyto Energy Trust Consolidated Statements of Comprehensive Income ($000 except per unit amounts) (unaudited) Three Months Ended Six Months Ended June 30 June 30 2010 2009 2010 2009 ---------------------------------------------------------------------------- Earnings for the period 24,696 29,189 61,571 92,763 Other comprehensive income Change in unrealized gain (loss) on cash flow hedges (1,344) 19,022 36,578 39,522 Realized (gain) loss on cash flow hedges (11,368) (17,629) (17,253) (30,890) ---------------------------------------------------------------------------- Comprehensive income 11,984 30,582 80,896 101,395 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- See accompanying notes Peyto Energy Trust Consolidated Statements of Accumulated Earnings and Accumulated Other Comprehensive Income ($000) (unaudited) Three Months Ended Six Months Ended June 30 June 30 2010 2009 2010 2009 ---------------------------------------------------------------------------- Accumulated earnings, beginning of period 95,153 132,503 99,749 110,238 Net earnings for the period 24,696 29,189 61,571 92,763 Distributions (Note 7) (43,622) (39,211) (85,093) (80,520) ---------------------------------------------------------------------------- Accumulated earnings, end of period 76,227 122,481 76,227 122,481 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Accumulated other comprehensive income, beginning of period 41,636 37,485 9,599 30,246 Other comprehensive income (loss) (12,712) 1,393 19,325 8,632 ---------------------------------------------------------------------------- Accumulated other comprehensive income, end of period 28,924 38,878 28,924 38,878 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- See accompanying notes Peyto Energy Trust Consolidated Statements of Cash Flows ($000) (unaudited) Three Months Ended Six Months Ended June 30 June 30 2010 2009 2010 2009 ---------------------------------------------------------------------------- Cash provided by (used in) Operating Activities Earnings for the period 24,696 29,189 61,571 92,763 Items not requiring cash: Future income tax recovery (555) (844) (1,418) (25,537) Depletion, depreciation and accretion 21,906 17,718 42,319 36,295 Change in non-cash working capital related to operating activities 9,876 4,130 5,834 (1,226) ---------------------------------------------------------------------------- 55,923 50,193 108,306 102,295 ---------------------------------------------------------------------------- Financing Activities Issuance of trust units (Note 6) 80,497 94,500 82,152 94,500 Issuance costs (Note 6) (3,968) (5,089) (3,968) (5,089) Cash distribution paid (net of DRIP) (41,977) (39,211) (81,227) (80,520) Increase (decrease) in bank debt (20,000) (50,000) (5,000) (40,000) Change in non-cash working capital related to financing activities 765 1,081 2,823 (2,097) ---------------------------------------------------------------------------- 15,317 1,281 (5,220) (33,206) ---------------------------------------------------------------------------- Investing Activities Additions to property, plant and equipment (37,451) (4,671) (85,925) (17,707) Change in non-cash working capital related to investing activities (24,513) (5,239) (7,885) (9,818) ---------------------------------------------------------------------------- (61,964) (9,910) (93,810) (27,525) ---------------------------------------------------------------------------- Net increase (decrease) in cash 9,276 41,564 9,276 41,564 Cash, beginning of period - - - - ---------------------------------------------------------------------------- Cash, end of period 9,276 41,564 9,276 41,564 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- See accompanying notes Peyto Energy TrustNotes to Consolidated Financial Statements(unaudited) June 30, 2010 and 20091. Summary of Significant Accounting PoliciesThe 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 PoliciesPending Accounting PronouncementsIn 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 June 30, December 31, ($000) 2010 2009 ---------------------------------------------------------------------------- Accounts receivable - general 42,246 51,150 Accounts receivable - income taxes 7,155 7,155 ---------------------------------------------------------------------------- 49,401 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 $7.3 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 currently in progress and will be complete by September 30, 2010. 4. Property, Plant and Equipment June 30, December 31, ($000) 2010 2009 ---------------------------------------------------------------------------- Property, plant and equipment 1,711,815 1,624,655 Accumulated depletion and depreciation (488,208) (446,253) ---------------------------------------------------------------------------- 1,223,607 1,178,402 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- At June 30, 2010 costs of $25.8 million (December 31, 2009 - $26.6 million) related to undeveloped land have been excluded from the depletion and depreciation calculation.5. Long-Term DebtThe 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 six months ended June 30, 2010 was 4.9% and 4.4% 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 by private placement - - 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 245,018 3,174 Trust units issued pursuant to OTUPP 548,845 6,987 ---------------------------------------------------------------------------- Balance, June 30, 2010 121,476,477 584,996 ---------------------------------------------------------------------------- Units IssuedOn 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 IssuedSubsequent to June 30, 2010, 69,375 trust units (48,301 pursuant to the DRIP and 21,074 pursuant to the OTUPP) were issued for net proceeds of $1.0 million. Subsequent to the issuance of these units, 121,545,852 trust units were outstanding.Per Unit AmountsEarnings per unit have been calculated based upon the weighted average number of units outstanding for three months ended June 30, 2010 of 119,419,799 (2009 - 106,315,798) and for the six months ended June 30, 2010 of 117,298,518 (2009 - 106,119,089). There are no dilutive instruments outstanding.7. Accumulated DistributionsThe Trust declared total distributions to the unitholders in the aggregate amount of $43.6 million in the three months ended June 30, 2010 (2009 - total $39.2 million) and $85.1 million for the six months ended June 30, 2010 (2008 - total $80.5 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 ---------------------------------------------------------------------------- (1) Distributions per trust unit are the amounts declared monthly to unitholders. Accumulated Earnings and Distributions June 30, December 31, ($000) 2010 2009 ---------------------------------------------------------------------------- Accumulated earnings, beginning of period 1,072,209 919,435 Earnings for the period 61,571 152,774 ---------------------------------------------------------------------------- Total accumulated earnings 1,133,780 1,072,209 Total accumulated distributions (1,057,553) (972,460) ---------------------------------------------------------------------------- Accumulated earnings, end of period 76,227 99,749 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- 8. Operating ExpensesThe 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 Six Months Ended June 30 June 30 ($000) 2010 2009 2010 2009 ---------------------------------------------------------------------------- Field expenses 7,377 6,728 14,510 14,123 Processing and gathering income (2,765) (2,531) (5,338) (5,366) ---------------------------------------------------------------------------- Total operating costs 4,612 4,197 9,172 8,757 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- 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 Six Months Ended June 30 June 30 ($000) 2010 2009 2010 2009 ---------------------------------------------------------------------------- General and administrative expenses 2,020 2,270 4,737 5,008 Overhead recoveries (945) (366) (1,826) (866) ---------------------------------------------------------------------------- Net general and administrative expenses 1,075 1,904 2,911 4,142 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- 10. Financial Instruments and Risk ManagementFinancial Instrument Classification and MeasurementFinancial 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 June 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 LiabilitiesThe 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 June 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 RiskMarket 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 ManagementThe 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 June 30, 2010 are as follows: Asset Asset Fair as at as at Effective Value June December Description Notional(1) Term Rate Level 30, 2010 31, 2009 ---------------------------------------------------------------------------- Natural gas financial swaps - AECO 28.06GJ(2) 2010- 2012 $ 5.52/GJ Level 1 32,367 9,936 ---------------------------------------------------------------------------- (1) Notional values as at June 30, 2010 (2) Millions of gigajoules ---------------------------------------------------------------------------- Natural Gas Price Period Hedged Type Daily Volume (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 June 30, 2010, the Trust had committed to the future sale of 28,055,000 gigajoules (GJ) of natural gas at an average price of $5.52 per GJ or $6.46 per mcf. Had these contracts been closed on June 30, 2010, the Trust would have realized a gain in the amount of $32.4 million. If the AECO gas price on June 30, 2010 were to increase by $1/GJ, the unrealized gain on these closed contracts would change by approximately $28.1 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 riskThe 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 six month periods ended June 30, 2010 would decrease by $1.0 million and $2.1 million respectively. An opposite change in interest rates will result in an opposite impact on earnings.Credit RiskA 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 six months ended June 30, 2010, approximately 97% was received from six companies (25%, 19%, 16%, 13%, 13% and 11%) (June 30, 2009 - 88%, five companies (25%, 20%, 16%, 14% and 13%)). 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 June 30, 2010, there was no impairment of any of the financial assets of the Trust.Liquidity RiskLiquidity 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 June 30, 2010: less than 1-2 2-5 ($000s) 1 Year Years Years Thereafter ---------------------------------------------------------------------------- Accounts payable and accrued liabilities 38,281 Distributions payable 13,885 Provision for future performance based compensation 9,232 2,311 Long-term debt(1) 430,000 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Revolving credit facility renewed annually (see Note 5) 11. Capital DisclosuresThe 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. June 30, December 31, ($000s) 2010 2009 ---------------------------------------------------------------------------- Unitholders' equity 691,141 612,483 Long-term debt 430,000 435,000 Working capital (surplus) deficit (1) (31,998) (1,822) ---------------------------------------------------------------------------- 1,089,143 1,045,661 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Current liabilities less current assets (includes unrealized hedging asset of $29.1 million (2009 - $8.7 million) 12. Supplemental Cash Flow Information Three Months Ended Six Months Ended June 30 June 30 ($000) 2010 2009 2010 2009 ---------------------------------------------------------------------------- Cash interest paid during the period 4,969 3,876 9,381 7,426 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- 13. Contingencies and CommitmentsFollowing is a summary of the Trust's commitments related to operating leases as at June 30, 2010. The Trust has no other contractual obligations or commitments as at June 30, 2010. ($000) June 30, 2010 ---------------------------------------------------------------------------- 2010 518 2011 1,036 2012 1,036 2013 1,036 2014 1,036 ---------------------------------------------------------------------------- 4,662 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Contingent LiabilityFrom 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 Corporate Secretary Officer Kathy Turgeon Vice-President, Finance and Chief Financial Officer 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 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 FOR FURTHER INFORMATION PLEASE CONTACT: Peyto Energy Trust Darren Gee President and CEO 403.261.6081 403.451.4100(FAX) www.peyto.com