In c5470 transmitted at 20:08e today, an error occurred in the
Confererence Call and Webcast section. An incorrect webcast address was
given. Corrected copy follows:
Peyto Energy Trust announces third quarter 2007 results
SYMBOL: PEY.UN - TSX
CALGARY, Nov. 7 /CNW/ - Peyto Energy Trust ("Peyto") is pleased to present the operating and financial results for the third quarter of the 2007 fiscal year. Peyto is a conventional oil and gas business that builds tight natural gas assets in Alberta's Deep Basin and produces one of the cleanest burning fossil fuels available.
Peyto is well known for owning high quality, sweet gas assets that exhibit long reserve life, low operating costs and high revenue per boe. The following summarizes the Trust's foundation:
- Long reserve life - Proved 14 years, Proved plus Probable 20 years,
at the end of 2006
- Low operating costs - $2.48/boe, three months ending September 30,
2007
- High revenue natural gas - $42.39/boe before hedging, $50.15/boe
after hedging, three months ending September 30, 2007
- Low base general and administrative costs - $0.82/boe, three months
ending September 30, 2007
- High field netback - $38.57/boe, three months ending September 30,
2007
- High operatorship - operates over 95% of its production
- Cash distributions - cash distributions of $44.4 million were 71% of
funds from operations for the three months ended September 30, 2007
- Low debt to funds from operations ratio - 1.7:1 (net debt, before
provision for future compensation, divided by annualized third
quarter 2007 funds from operations)
- Distribution growth - distributions have been increased 5 times; they
have never decreased, and are now 87% higher than when the trust was
formed in July, 2003
- Since inception, Peyto has raised a total of $406 million issuing
units from treasury, accumulated earnings of $667 million, and
distributed $578 million to unitholders
- Transparent capital structure - no convertible debentures, no
exchangeable shares, no stock options, no warrants
The third quarter was highlighted by sustained distributions, an
accelerated pace of capital investment and improved capital efficiency that
maintained Peyto's financial flexibility. The following summarizes performance
highlights of the business for the third quarter of 2007:
- Capital expenditures - $42.6 million was invested into finding and
developing new natural gas reserves, up from $12.9 million in the
previous quarter, but down from $71.2 million in Q3 2006. Capital
expenditures for the first three quarters of 2007 were $86 million
versus $284 million for the first three quarters of 2006, a reduction
of 70%
- Production - decreased 16% from 23,422 boe/d in the third quarter of
2006 to 19,740 boe/d in the third quarter of 2007
- Production per unit - decreased 18% per trust unit from the third
quarter of 2006, after adjusting for debt and future unrealized
performance based compensation
- Per unit funds from operations - decreased 13% from the previous year
to $0.69/unit
- Commodity prices - natural gas prices, both before and after hedges,
were lower in Q3 2007 with prices averaging $6.07/mcf and $7.61/mcf
respectively versus $6.53/mcf and $7.81/mcf in Q3 2006
- Hedging - a $14.1 million gain for the three months ending
September 30, 2007 was realized
- Distributions per unit were unchanged from the third quarter of 2006
while the cash payout ratio increased to 71% from 61% in Q3 2006. A
total of $44.4 million or $0.42 per unit was distributed to
unitholders in the third quarter of 2007
- Net debt increased 2% from $431 million in Q3 2006 to $439 million in
Q3 2007. This leaves available borrowing capacity of $86 million on
bank lines of $525 million
Natural gas volumes recorded in thousand cubic feet (mcf) are converted to
barrels of oil equivalent (boe) using the ratio of six (6) thousand cubic feet
to one (1) barrel of oil (bbl).
-------------------------------------------------------------------------
3 Months Ended Sep 30 % 9 Months Ended Sep 30 %
2007 2006 Change 2007 2006 Change
-------------------------------------------------------------------------
Operations
Production
Natural gas
(mcf/d) 97,000 115,304 (16)% 101,632 112,905 (10)%
Oil & NGLs
(bbl/d) 3,573 4,205 (15)% 3,573 4,164 (14)%
Barrels of oil
equivalent
(boe/d @
6:1) 19,740 23,422 (16)% 20,512 22,982 (11)%
Product prices
Natural gas
($/mcf) 7.61 7.81 (3)% 8.68 8.33 4%
Oil & NGLs
($/bbl) 70.51 64.50 9% 65.34 62.89 4%
Operating
expenses
($/boe) 2.48 1.90 31% 2.67 1.99 34%
Transportation
($/boe) 0.58 0.58 0% 0.58 0.60 (3)%
Field netback
($/boe) 38.57 36.58 5% 41.59 38.72 7%
General &
administrative
expenses
($/boe) 0.82 0.55 49% 0.97 0.35 177%
Interest expense
($/boe) 3.10 2.52 23% 3.00 1.97 52%
Financial
($000, except
per unit)
Revenue 91,070 107,844 (16)% 304,646 328,313 (7)%
Royalties (net
of ARTC) 15,481 23,680 (35)% 53,541 69,175 (23)%
Funds from
operations 62,938 72,360 (13)% 210,647 228,485 (8)%
Funds from
operations
per unit 0.60 0.69 (13)% 1.99 2.17 (8)%
Total
distributions 44,399 44,111 1% 133,148 129,549 3%
Total
distributions
per unit 0.42 0.42 0% 1.26 1.24 2%
Payout ratio 71 61 16% 63 57 11%
Cash
distributions
(net of DRIP) 44,399 41,019 8% 133,148 113,999 17%
Payout ratio 71 57 25% 63 50 26%
Earnings 39,886 46,155 (14)% 135,594 148,216 (9)%
Earnings per
diluted unit 0.37 0.44 (16)% 1.28 1.42 (10)%
Capital
expenditures 42,598 71,223 (40)% 86,024 283,513 (70)%
Weighted
average
trust units
out-
standing 105,712,364 104,924,702 1% 105,656,359 104,554,325 1%
As at
September 30
Net debt
(before future
compensation
expense) 439,325 431,097
Unitholders'
equity 507,744 481,863
Total assets 1,164,561 1,110,547
-------------------------------------------------------------------------
3 Months Ended 9 Months Ended
Sep 30 Sep 30
2007 2006 2007 2006
-------------------------------------------------------------------------
Net Earnings 39,886 46,155 135,594 148,216
Items not requiring cash:
Non-cash provision for (recovery
of) performance based compensation 202 (2,005) 640 192
Future income tax expense 4,808 7,821 17,774 19,376
Depletion, depreciation and
accretion 18,042 20,389 56,639 60,701
-------------------------------------------------------------------------
Funds from operations (1) 62,938 72,360 210,647 228,485
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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. We believe that funds from operations is an important parameter to measure the value of an asset when combined with reserve life. Funds from operations is not a measure recognized by Canadian generally accepted accounting principles ("GAAP") and does not have a standardized meaning prescribed by GAAP. Therefore, funds from operations, as defined by Peyto, may not be comparable to similar measures presented by other issuers, and investors are cautioned that funds from operations should not be construed as an alternative to net earnings, cash flow from operating activities or other measures of financial performance calculated in accordance with GAAP. Funds from operations cannot be assured and future distributions may vary.
Quarterly Review
During the third quarter, Peyto experienced improved capital efficiency from lower service costs and reduced industry activity. Accordingly, Peyto increased its pace of activity which resulted in $42.6 million being invested into designing, drilling and building new producing gas assets in the Deep Basin. Drilling and completions accounted for $31.5 million while wellsite equipment, pipelines and facilities accounted for $10.1 million. Acquisition of new land and seismic data made up the remaining $1.0 million.
-------------------------------------------------------------------------
2007 2006
$ millions Q3 Q2 Q1 Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Funds from
operations 62.9 69.3 78.4 77.4 72.4 77.5 78.6
Distributions -44.4 -44.4 -44.4 -44.2 -44.1 -43.9 -41.5
Capital
Expenditures -42.6 -12.9 -30.5 -28.4 -71.2 -67.2 -145.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total -24.1 12.0 3.5 4.7 -43.0 -33.6 -108.0
-------------------------------------------------------------------------
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---------------------------------
2005
$ millions Q4 Q3
---------------------------------
Funds from
operations 86.6 77.2
Distributions -36.8 -35.5
Capital
Expenditures -107.6 -93.0
---------------------------------
---------------------------------
Total -57.8 -51.3
---------------------------------
---------------------------------
In the third quarter, the Trust drilled 19 gross (13.9 net, 73% working interest) gas wells, completed 27 gross (22.8 net) gas zones and brought 16 gross (13.6 net) zones on production. Many of these new zones were brought on towards the latter part of the quarter and, as a result, were not fully able to offset the base production decline. Production for the quarter averaged 19,740 boe/d, down from 20,509 boe/d in the second quarter.
Despite spiking power prices in July, operating costs were $2.48/boe for the third quarter and $2.67/boe for the year to date. Peyto continues to be one of the lowest cost producers of natural gas in North America. Royalties paid out, as a percentage of revenues, were 17% for the period or $8.52/boe.
Natural gas prices for the third quarter averaged $7.61/mcf and liquids prices averaged $70.51/bbl combining to deliver revenue of $50.15/boe versus $50.05/boe in Q3 2006. The combination of high quality production and low operating costs yielded very strong field netbacks of $38.57/boe, 5% higher than a year ago.
Activity Update
To date in 2007, Peyto has drilled 45 gross (36 net) wells and brought on production 48 gross (36.6 net) gas zones. The increased level of activity since spring breakup has resulted in building over 3,500 boe/d of new production for the year. Current production is approximately 21,000 boe/d. Peyto's Chime pipeline is now operational and connects gas production from this area to its Kakwa gas plant. Additional development in the Chime area will now enjoy a much improved processing cost. Fourth quarter plans include slightly reduced activity to maintain financial flexibility in light of softer 2007/08 winter gas prices relative to the gas price offered for the following two seasons. Two to three drilling rigs will be focused primarily in the Greater Sundance area while additional opportunities are finalized in new expansion areas.
Marketing
US working gas in storage is currently at the high end of the five year range. This has set the upcoming winter price for natural gas around US$8.50/mmbtu in New York. Unfortunately, this is not the price received in Alberta. After adjusting for currency exchange and transportation from Alberta to New York, the gas price is reduced to approximately CDN$7.00/mmbtu. The recent strength of the Canadian dollar has increased the price gap between these two receipt points. Despite this negative currency effect, the natural gas price offered in Alberta for this winter is still higher than the monthly average gas price received in three of the last four winters.
Consistent with our marketing strategy, Peyto has committed to forward sell 91,500 barrels of crude oil at an average price of $78.55 per barrel and 9,320,000 gigajoules (GJ) of natural gas at an average price of $8.05 per GJ or $9.42 per mcf. The high heat content nature of Peyto's gas production generates this 17% premium price by volume. Had these contracts been closed on September 30, 2007, the Trust would have realized a gain of $18.5 million.
Alberta's New Royalty Framework
On October 25, 2007, the Provincial Government of Alberta announced a new royalty framework. The new framework incorporated some of the recommendations from the Alberta Royalty Review Panel's September report which was entitled "Our Fair Share." The new royalty framework outlines new royalty rates for all oil and gas produced in the Province starting January 1, 2009. In almost all cases and for all foreseeable commodity prices, the government take will increase. Effectively, 100% of Peyto's reserve assets are located in Alberta and will be subject to the new royalty rates. Peyto has evaluated the new royalty rates, inclusive of depth factor adjustments, against the current production and at current gas prices, and has determined that they should have a minor negative impact on cashflow but an immaterial impact on the overall producing net asset value.
In its 9 year history, Peyto has invested over $1.4 billion in capital projects in Alberta. Those investments have employed thousands of oilfield workers every year in the greater Edson and Hinton areas. As a result of those investments and by taking those risks, Peyto has found and developed gas reserves that have already paid over $400 million in royalties and may ultimately pay in excess of $1.6 billion. "As long as Alberta remains good for Peyto, Peyto will remain good for Alberta."
Outlook
In Alberta, industry utilization of services remains low, putting pressure on the service sector to continue reducing rates. This ongoing cost savings is improving Peyto's return on capital investment, and will ultimately assist in offsetting the additional royalty burden, thus allowing Peyto to maintain its pace of activity. The Peyto team continues to add to the abundance of Deep Basin drilling prospects already in inventory and, as capital efficiency improves, available leverage can be employed to accelerate those opportunities. Peyto's financial flexibility has been tested and proven over the last few quarters, supported by the quality of the underlying assets. The total production base is stabilizing, which means less capital is required to maintain production and grow reserves. The sustainability of the Peyto model is becoming self evident. Unitholders are encouraged to visit the Peyto website at www.peyto.com where there is a wealth of information designed to inform and educate investors.
Conference Call and Webcast
A conference call will be held with the senior management of Peyto to answer questions with respect to the 2007 third quarter results on Thursday, November 8, 2007 at 9:00 a.m. Mountain Standard Time (MST), 11:00 a.m. Eastern Standard Time (EST). To participate, please call 1-416-644-3422 (Toronto area) or 1-800-731-5319 for all other participants. The conference call will also be available on replay by calling 1-416-640-1917 (Toronto area) or 1-877-289-8525 for all other parties, using passcode 21249902 followed by the pound key. The replay will be available at 11:00 a.m. MST, 1:00 p.m. EST Thursday, November 8, 2007 until midnight EST on Thursday, November 15, 2007. The conference call can also be accessed through the internet at http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID(equal sign)2043140 . After this time the conference call will be archived on the Peyto Energy Trust website at www.peyto.com.
Darren Gee
President and CEO
November 7, 2007
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 disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
Management's discussion and analysis
This Management's Discussion and Analysis ("MD&A") should be read in conjunction with the unaudited interim consolidated financial statements for the period ended September 30, 2007 and the audited consolidated financial statements of Peyto Energy Trust ("Peyto") for the year ended December 31, 2006. The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles ("GAAP").
The Trust was created by way of a Plan of Arrangement effective July 1, 2003 which reorganized Peyto Exploration & Development Corp. ("PEDC") from a corporate entity into a trust. Accordingly, the consolidated financial statements were reported on a continuity of interests basis. This discussion provides management's analysis of Peyto's historical financial and operating results and provides estimates of Peyto's future financial and operating performance based on information currently available. Actual results will vary from estimates and the variances may be significant. Readers should be aware that historical results are not necessarily indicative of future performance. This MD&A was prepared using information that is current as of November 6, 2007. Additional information about Peyto, including the most recently filed annual information form is available at www.sedar.com.
Certain information set forth in this Management's Discussion and Analysis, including management's assessment of the Trust'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 that Peyto will derive there from. Peyto disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
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. We believe 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.
To the best of our knowledge, Peyto's foreign ownership level currently stands at approximately 33 percent, well below the level that would jeopardize Peyto's status as a mutual fund trust under current or proposed legislation.
All references are to Canadian dollars unless otherwise indicated. 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).
Alberta Government Crown Royalty Regime Change
On October 25, 2007, the Provincial Government of Alberta announced a new royalty framework. The new framework incorporated some of the recommendations from the Alberta Royalty Review Panel's September Report which was entitled "Our Fair Share." The new royalty framework outlines new royalty rates for all oil and gas produced in the Province starting January 1, 2009. In almost all cases, and for all foreseeable commodity prices, the government take will be increased. Effectively, 100% of Peyto's reserve assets are located in Alberta and are subject to the new royalty rates. Peyto has evaluated the new royalty rates, inclusive of depth factor adjustments, against the current production and at current gas prices, and has determined that they should have a minor negative impact on cashflow but an immaterial impact on producing net asset value.
Federal Government's Trust Tax Legislation
On June 12, 2007, Bill C-52 ("Bill") was enacted for Canadian GAAP. The Bill enacts the October 31, 2006 proposals to impose a new tax on distributions from flow-through entities, including publicly traded income trusts. This has not resulted in any change in the consolidated future income tax calculation.
Under this Bill, existing income trusts will be subject to the new measures commencing in their 2011 taxation year, following a four-year grace period. In simplified terms, under the proposed tax plan, income distributions will first be taxed at the trust level at a special rate estimated to be 31.5%. Income distributions to individual unitholders will then be treated as dividends from a Canadian corporation and eligible for the dividend tax credit. Income distributions to corporations resident in Canada will be eligible for full deduction as tax free intercorporate dividends. Tax-deferred accounts (RRSPs, RRIFs and Pension Plans) will continue to pay no tax on distributions. Non-resident unitholders will be taxed on distributions at the non-resident withholding tax rate for dividends. The net impact on Canadian taxable investors is expected to be minimal because they can take advantage of the dividend tax credit. However, as a result of the 31.5% Distribution Tax at the trust level, distributions to tax-deferred accounts will be reduced by approximately 31.5%, and distributions to non-residents will be reduced by approximately 26.5%. Pursuant to the October 30, 2007 mini-budget, these rates may be decreased by 2%. Peyto is currently assessing the proposals and the potential implications to the Trust. Structural alternatives will continue to be reviewed to ensure that Peyto's structure is as efficient as possible.
Climate Change Programs
On March 8, 2007, the Alberta government introduced legislation to reduce greenhouse gas emission intensity. Bill 3 states that facilities emitting more than 100,000 tonnes of greenhouse gases per year must reduce their emissions intensity by 12 per cent over the average emissions levels of 2003, 2004 and 2005; if they are not able to do so, these facilities will be required to pay $15 per tonne for every tonne above the 12 per cent target, beginning on July 1, 2007. At this time, the Trust has determined that there is currently no impact of this legislation on Peyto's existing facilities ownership.
In April 2007, the Federal Government announced a new climate change plan that calls for greenhouse gas emissions to be reduced by 20 per cent below current levels by 2020. Firms may employ the following strategies to achieve the targets. They will be able to:
- make in-house reductions; - take advantage of domestic emissions trading; - purchase offsets; - use the Clean Development Mechanism under the Kyoto Protocol; and, - invest in a technology fund.
The Trust is waiting for additional information so as to fully assess what impact, if any, this new legislation will have on our operations.
United States Proposed Changes to Qualifying Dividends
A bill was introduced into United States Congress on March 23, 2007 that could deny qualified dividend income treatment to the distributions made by the Trust to its U.S. unitholders. The bill is in the first step of the legislative process and it is uncertain whether it will eventually be passed into law in its current form. If the bill is passed in its current form, distributions received by U.S. unitholders would no longer qualify for the 15 per cent qualified dividend tax rate.
OVERVIEW
Peyto is a Canadian energy trust involved in the development and production of natural gas in Alberta's deep basin. As at December 31, 2006, the total proved plus probable reserves were 163.5 million barrels of oil equivalent with a reserve life of 20 years as evaluated by the independent petroleum engineers. Production is weighted approximately 83% natural gas and 17% natural gas liquids and oil.
The Peyto model is designed to deliver growth in its value, assets, production and income, all on a per unit basis. The model is built around three key principles:
- Use technical expertise to achieve the best return on capital
employed, through the development of internally generated drilling
projects.
- Maintain a low payout ratio designed to efficiently fund a growing
inventory of drilling projects.
- Build an asset base which is made up of high quality long life
natural gas reserves.
Operating results over the last eight years indicate that these principles
have been successfully implemented. This business model makes Peyto a truly
unique energy trust.
QUARTERLY FINANCIAL INFORMATION
-------------------------------------------------------------------------
2007 2006
($000 except per unit amounts) Q3 Q2 Q1 Q4
-------------------------------------------------------------------------
Total revenue (net of royalties) 75,589 83,017 92,499 91,425
Funds from operations 62,938 69,345 78,364 77,360
Per unit - basic 0.60 0.66 0.74 0.74
Per unit - diluted 0.60 0.66 0.74 0.74
Earnings (loss) 39,886 38,825 56,883 47,012
Per unit - basic 0.37 0.37 0.54 0.44
Per unit - diluted 0.37 0.37 0.54 0.44
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2006 2005
($000 except per unit amounts) Q3 Q2 Q1 Q4
-------------------------------------------------------------------------
Total revenue (net of royalties) 84,164 88,515 86,459 94,111
Funds from operations 72,360 77,507 78,617 86,607
Per unit - basic 0.69 0.74 0.76 0.85
Per unit - diluted 0.69 0.74 0.76 0.85
Earnings (loss) 46,155 56,768 45,293 60,745
Per unit - basic 0.44 0.54 0.44 0.60
Per unit - diluted 0.44 0.54 0.44 0.60
-------------------------------------------------------------------------
RESULTS OF OPERATIONS
Production
-------------------------------------------------------------------------
Three Months ended Nine Months ended
Sep 30 Sep 30
2007 2006 2007 2006
-------------------------------------------------------------------------
Natural gas (mmcf/d) 97.0 115.3 101.6 112.9
Oil & natural gas liquids (bbl/d) 3,573 4,205 3,573 4,164
Barrels of oil equivalent (boe/d) 19,740 23,422 20,512 22,982
-------------------------------------------------------------------------
Natural gas production averaged 97.0 mmcf/d in the third quarter of 2007, 16 percent lower than the 115.3 mmcf/d reported for the same period in 2006. Oil and natural gas liquids production averaged 3,573 bbl/d, a decrease of 15 percent from 4,205 bbl/d reported in the prior year. Third quarter production decreased 16 percent from 23,422 boe/d to 19,740 boe/d. The production decreases are attributable to Peyto's reduced drilling program and natural resource declines.
Commodity Prices
-------------------------------------------------------------------------
Three Months ended Nine Months ended
Sep 30 Sep 30
2007 2006 2007 2006
-------------------------------------------------------------------------
Natural gas ($/mcf) 6.07 6.53 7.47 7.64
Hedging - gas ($/mcf) 1.54 1.28 1.21 0.69
-------------------------------------------------------------------------
Natural gas - after hedging ($/mcf) 7.61 7.81 8.68 8.33
-------------------------------------------------------------------------
Oil and natural gas liquids ($/bbl) 69.56 65.29 63.22 65.38
Hedging - oil ($/bbl) 0.95 (0.79) 2.12 (2.49)
-------------------------------------------------------------------------
Oil and natural gas liquids -
after hedging ($/bbl) 70.51 64.50 65.34 62.89
-------------------------------------------------------------------------
Total Hedging ($/boe) 7.76 6.14 6.38 2.95
-------------------------------------------------------------------------
Peyto's natural gas price, before hedging gains, averaged $6.07/mcf during
the third quarter of 2007, a decrease of 7 percent from $6.53/mcf reported for
the equivalent period in 2006. Oil and natural gas liquids prices before
hedging gains averaged $69.56/bbl up 7 percent from $65.29/bbl a year earlier.
Hedging activity for the third quarter of 2007 accounted for $7.76/boe of
Peyto's price achieved.
Revenue
-------------------------------------------------------------------------
Three Months ended Nine Months ended
Sep 30 Sep 30
($000) 2007 2006 2007 2006
-------------------------------------------------------------------------
Natural gas 54,116 69,347 207,229 235,500
Oil and natural gas liquids 22,866 25,259 61,671 74,324
Hedging gain (loss) 14,088 13,238 35,746 18,489
-------------------------------------------------------------------------
Total revenue 91,070 107,844 304,646 328,313
-------------------------------------------------------------------------
For the three months ended September 30, 2007, gross revenue decreased
16 percent to $91.1 million from $107.8 million for the same period in 2006.
The decrease in revenue for the period was a result of decreased production
volumes and lower natural gas prices as detailed in the following table:
-------------------------------------------------------------------------
Three Months ended Nine Months ended
Sep 30 Sep 30
2007 2006 $million 2007 2006 $million
-------------------------------------------------------------------------
Total Revenue, Sept 30,
2006 107.8 328.3
-------------------------------------------------------------------------
Revenue change due to:
-------------------------------------------------------------------------
Natural gas
Volume (mmcf) 8,924 10,348 (11.3) 27,746 30,823 (25.6)
Price ($/mcf) $7.61 $7.96 (3.1) $8.68 $8.33 9.7
Oil & NGL
Volume (mbbl) 329 381 (3.5) 976 1,137 (10.2)
Price ($/bbl) $70.51 $66.94 1.2 $65.34 $62.89 2.4
-------------------------------------------------------------------------
Total Revenue, Sept 30,
2007 91.1 304.6
-------------------------------------------------------------------------
Royalties
Royalties are paid to the owners of the mineral rights with whom leases
are held, including the provincial government of Alberta. Alberta gas crown
royalties are invoiced on the Crown's share of production based on a monthly
established Alberta Reference Price. The Alberta Reference Price is a monthly
weighted average price of gas consumed in Alberta and gas exported from
Alberta reduced for transportation and marketing allowances.
-------------------------------------------------------------------------
Three Months ended Nine Months ended
Sep 30 Sep 30
($000 except per unit amounts) 2007 2006 2007 2006
-------------------------------------------------------------------------
Royalties 15,481 23,805 53,541 69,425
ARTC - (125) - (250)
-------------------------------------------------------------------------
15,481 23,680 53,541 69,175
-------------------------------------------------------------------------
% of sales 17.0 22 17.6 21
$/boe 8.52 10.99 9.56 11.03
-------------------------------------------------------------------------
For the third quarter of 2007, royalties averaged $8.52/boe or approximately 17.0 percent of Peyto's total petroleum and natural gas sales. The royalty rate expressed as a percentage of sales, will fluctuate from period to period due to the fact that the Alberta Reference Price can differ significantly from the commodity prices obtained by the Trust and that hedging gains and losses are not subject to royalties. As average per well production rates decline, the associated effective Crown Royalty rate will decrease. In addition, Peyto will receive Deep Gas Royalty Holiday or Marginal Deep Gas Well Program benefits until December 31, 2008, which further decrease our crown royalty rate. Effective January 1, 2007, the Alberta Government discontinued the Alberta Royalty Tax Credit ("ARTC") program. In the 9 year history of the company, Peyto has invested over $1.4 billion in capital projects and has found and developed gas reserves that have paid over $400 million in royalties.
Operating Costs & Transportation
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 gas reduces operating expenses.
-------------------------------------------------------------------------
Three Months ended Nine Months ended
Sep 30 Sep 30
2007 2006 2007 2006
-------------------------------------------------------------------------
Operating costs ($000)
Field expenses 6,476 6,245 21,297 18,404
Processing and gathering income (1,976) (2,161) (6,321) (5,939)
-------------------------------------------------------------------------
Total operating costs 4,500 4,084 14,976 12,465
-------------------------------------------------------------------------
$/boe 2.48 1.90 2.67 1.99
-------------------------------------------------------------------------
Transportation 1,045 1,256 3,245 3,767
-------------------------------------------------------------------------
$/boe 0.58 0.58 0.58 0.60
-------------------------------------------------------------------------
Operating costs were $4.5 million in the third quarter of 2007 compared to
$4.1 million during the same period a year earlier. Transportation expense
remained constant. On a unit-of-production basis, operating costs averaged
$2.48/boe in the third quarter of 2007 compared to $1.90/boe for the third
quarter of 2006.
Netbacks
-------------------------------------------------------------------------
Three Months ended Nine Months ended
Sep 30 Sep 30
($/boe) 2007 2006 2007 2006
-------------------------------------------------------------------------
Sale Price 50.15 50.05 54.40 52.34
Less:
Royalties 8.52 10.99 9.56 11.03
Operating costs 2.48 1.90 2.67 1.99
Transportation 0.58 0.58 0.58 0.60
-------------------------------------------------------------------------
Field netback 38.57 36.58 41.59 38.72
General and administrative 0.82 0.55 0.97 0.35
Interest on long-term debt 3.10 2.52 3.00 1.97
Cash netback 34.65 33.51 37.62 36.40
-------------------------------------------------------------------------
Field netbacks represent the profit margin associated with the production
and sale of petroleum and natural gas. The primary factors that produce
Peyto's strong netbacks are a low cost structure and the high heat content of
its natural gas that results in higher commodity prices.
General and Administrative Expenses
-------------------------------------------------------------------------
Three Months ended Nine Months ended
Sep 30 Sep 30
2007 2006 2007 2006
-------------------------------------------------------------------------
G&A expenses ($000) 2,536 2,556 5,059 6,971
Overhead recoveries (1,053) (1,362) (2,167) (4,762)
-------------------------------------------------------------------------
Net G&A expenses 1,483 1,194 5,428 2,209
-------------------------------------------------------------------------
$/boe 0.82 0.55 0.97 0.35
-------------------------------------------------------------------------
General and administrative expenses before overhead recoveries decreased
1% from $2.6 million in the third quarter of 2006 to $2.5 million for the same
period in 2007. Net of overhead recoveries associated with the capital
expenditures program, general and administrative costs increased to $0.82 per
boe in the third quarter of 2007 from $0.55 per boe in the third quarter of
2006. Third quarter 2007 overhead recoveries were 23% lower than third quarter
2006 recoveries due to the reduction in capital expenditures.
Interest Expense
-------------------------------------------------------------------------
Three Months ended Nine Months ended
Sep 30 Sep 30
2007 2006 2007 2006
-------------------------------------------------------------------------
Interest expense ($000) 5,623 5,432 16,809 12,374
$/boe 3.10 2.52 3.00 1.97
-------------------------------------------------------------------------
Third quarter 2007 interest expense was $5.6 million or $3.10/boe compared to $5.4 million or $2.52/boe a year earlier. During the third quarter of 2007, average debt levels were $412 million as compared to $341 million in the third quarter of 2006. Interest rates continue to be favorable and are not expected to increase substantially in the short-term. The average interest rate for the third quarter of 2007 was 5.6% compared to 4.8% for the third quarter of 2006.
Depletion, Depreciation and Accretion
The 2007 third quarter provision for depletion, depreciation and accretion totaled $18.0 million as compared to $20.4 million in 2006. On a unit-of-production basis, depletion, depreciation and accretion costs averaged $9.93/boe as compared to $9.46/boe in 2006.
Income Taxes
The current provision for future income tax was $17.8 million (2006 - $19.4 million). Peyto's trust structure is unique and was designed to provide for discretion at the operating trust level to distribute taxable income to the Trust. Resource pools are generated from the capital program, which are available to offset current and future income tax liabilities. Unitholders benefit as the Trust may use these resource pools to increase the tax free return of capital component of the cash distributions.
MARKETING
Commodity Price Risk Management
Effective January 1, 2007, the Trust adopted the Canadian Institute of Chartered Accountants ("CICA") Section 3855, "Financial Instruments - Recognition and Measurement," Section 3865, "Hedges," Section 1530, "Comprehensive Income" and Section 3861, "Financial Instruments - Disclosure and Presentation." The Trust has adopted these standards retroactively without restatement and the comparative interim consolidated financial statements have not been restated. Transition amounts have been recorded in retained earnings or accumulated other comprehensive income ("AOCI"). See Note 2 to the Consolidated Financial Statements.
The Trust is a party to certain off balance sheet derivative financial instruments, including fixed price contracts. The Trust enters into these forward contracts with well established counter-parties for the purpose of protecting a portion of its future revenues from the volatility of oil and natural gas prices. During the third quarter of 2007, a hedging gain of $14.1 million was recorded as compared to $13.2 million in the third quarter of 2006. A summary of contracts outstanding in respect of the hedging activities are as follows:
Weighted
Average
Crude Oil Price
Period Hedged Type Daily Volume (CAD)
-------------------------------------------------------------------------
October 1 to December 31, 2007 Fixed price 200 bbl $77.51/bbl
October 1 to December 31, 2007 Fixed price 300 bbl $78.75/bbl
January 1 to March 31, 2008 Fixed price 200 bbl $78.55/bbl
January 1 to March 31, 2008 Fixed price 300 bbl $79.05/bbl
Weighted
Average
Natural Gas Price
Period Hedged Type Daily Volume (CAD)
-------------------------------------------------------------------------
April 1 to October 31, 2007 Fixed price 5,000 GJ $8.60/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $7.50/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $7.25/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $7.51/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $7.50/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $7.60/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $7.60/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $7.80/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $7.50/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $7.70/GJ
April 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $8.35/GJ
April 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $8.90/GJ
Nov 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $8.85/GJ
Nov 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $9.06/GJ
Nov 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $9.10/GJ
Nov 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $8.55/GJ
Nov 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $6.40/GJ
Nov 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $6.30/GJ
Dec 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $6.70/GJ
April 1 to October 31, 2008 Fixed price 5,000 GJ $7.85/GJ
April 1 to October 31, 2008 Fixed price 5,000 GJ $6.60/GJ
April 1 to October 31, 2008 Fixed price 5,000 GJ $6.40/GJ
April 1, 2008 to March 31, 2009 Fixed price 5,000 GJ $6.82/GJ
Nov 1, 2008 to March 31, 2009 Fixed price 5,000 GJ $7.25/GJ
Nov 1, 2008 to March 31, 2009 Fixed price 5,000 GJ $7.50/GJ
As at September 30, 2007, the Trust had committed to the future sale of 91,500 barrels of crude oil at an average price of $78.55 per barrel and 9,320,000 gigajoules (GJ) of natural gas at an average price of $8.05 per GJ or $9.42 per mcf based on the historical heating value of Peyto's natural gas. Had these contracts been closed on September 30, 2007, the Trust would have realized a gain in the amount of $18.5 million.
Commodity Price Sensitivity
Low operating costs, low distribution ratio and long reserve life reduce Peyto's sensitivity to changes in commodity prices.
Currency Risk Management
The Trust is exposed to fluctuations in the Canadian/US dollar exchange ratio since the natural gas and oil sales are effectively priced in US dollars and converted to Canadian dollars. In the short term, this risk is mitigated indirectly as a result of a commodity hedging strategy that is conducted at Canadian prices. Over the long term, the Canadian dollar tends to rise as oil prices rise. There is a similar correlation between oil and gas prices. Currently Peyto has not entered into any agreements to further manage this specific risk.
Interest Rate Risk Management
The Trust is exposed to interest rate risk in relation to interest expense on its revolving demand facility. Currently we have not entered into any agreements to manage this risk. At September 30, 2007, the increase or decrease in earnings for each 100 bps change in interest rate paid on the outstanding revolving demand loan amounts to approximately $4.0 million per annum.
LIQUIDITY AND CAPITAL RESOURCES
Funds from Operations
-------------------------------------------------------------------------
Three Months ended Nine Months ended
Sep 30 Sep 30
($000) 2007 2006 2007 2006
-------------------------------------------------------------------------
Net earnings 39,886 46,155 135,594 148,216
Items not requiring cash:
Non-cash provision for
performance based compensation 202 (2,005) 640 192
Future income tax expense 4,808 7,821 17,774 19,376
Depletion, depreciation &
accretion 18,042 20,389 56,639 60,701
-------------------------------------------------------------------------
Funds from operations 62,938 72,360 210,647 228,485
-------------------------------------------------------------------------
For the third quarter ended September 30, 2007, funds from operations totaled $62.9 million or $0.60 per unit, as compared to $72.4 million, or $0.69 per unit during the same period in 2006. Peyto's policy is to maintain a sustainable distribution to unitholders, retaining the balance to fund its growth oriented capital expenditures program. Earnings and cash flow are highly sensitive to changes in commodity prices, exchange rates and other factors that are beyond Peyto's control. Current volatility in commodity prices creates uncertainty as to the funds from operations and capital expenditure budget. Accordingly, results are assessed throughout the year and operational plans revised as necessary to reflect the most current information.
Revenues will be impacted by drilling success and production volumes as well as external factors such as the market prices for natural gas and crude oil and the exchange rate of the Canadian dollar relative to the US dollar.
Bank Debt
The Trust has an extendible revolving term credit facility with a syndicate of financial institutions in the amount of $525 million including a $505 million revolving facility and a $20 million operating facility. Available borrowings are limited by a borrowing base, which is based on the value of petroleum and natural gas assets as determined by the lenders. The loan is reviewed annually and may be extended at the option of the lender for an additional 364 day period. If not extended, the revolving facility will automatically convert to a one year and one day non-revolving term loan. The loan has therefore been classified as long-term on the balance sheet. The average borrowing rate for the third quarter of 2007 was 5.6% (2006 - 4.8%).
At September 30, 2007, $410 million was drawn under the facility. Working capital liquidity is maintained by drawing from and repaying the unutilized credit facility as needed. At September 30, 2007, the working capital deficit was $10.9 million.
Peyto believes funds generated from operations, together with borrowings under the credit facility and proceeds from equity issued will be sufficient to finance current operations and planned capital expenditure program. The total amount of capital invested in 2007 will be driven by the number and quality of projects generated. Capital will only be invested if it meets the long term objectives of the Trust. The majority of the capital program will involve drilling, completion and tie-in of lower risk development gas wells. Peyto's rapidly scaleable business model has the flexibility to match planned capital expenditures to actual cash flow.
Capital
Peyto implemented a Distribution Reinvestment Plan ("DRIP") effective with the March 2005 distribution whereby eligible unitholders may elect to reinvest their monthly cash distributions in additional trust units at a 5% discount to market price. On November 21, 2005 the DRIP plan was amended to incorporate 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. Both the DRIP and the OTUPP were suspended effective August 31, 2006 due to unfavorable market conditions.
On March 15, 2007 the Trust completed a private placement of 175,780 trust units to employees and consultants for net proceeds of $2,824,785. These trust units were issued on March 15, 2007. On March 15, 2007, subsequent to the issuance of these units, 105,712,364 trust units were outstanding (December 31, 2006 - 105,251,394).
Authorized: Unlimited number of voting trust units
Issued and Outstanding:
Trust Units (no par value) Number of Amount ($000) Shares/Units $ ------------------------------------------------------------------------- Balance, December 31, 2005 102,333,847 328,736 Trust units issued by private placement 1,393,940 34,378 Trust units issued pursuant to DRIP 690,387 16,301 Trust units issued pursuant to OTUPP 833,220 19,019 Balance, December 31, 2006 105,251,394 398,434 Trust units issued by private placement 460,970 7,867 ------------------------------------------------------------------------- Balance, September 30, 2007 105,712,364 406,301 ------------------------------------------------------------------------- -------------------------------------------------------------------------
Performance Based Compensation
The Trust awards performance based compensation to employees and key consultants annually. The performance based compensation is comprised of market and reserve value based components.
The reserve value based component is 4% of the incremental increase in value, if any, as adjusted to reflect changes in debt, equity and distributions, of proved producing reserves calculated using a constant price at December 31 of the current year and a discount rate of 8%. This methodology can generate interim results which vary significantly from the final compensation paid. No provision for the reserve value based component was recorded for the first three quarters of 2007.
Under the market based component, rights with a three year vesting period are allocated to employees and key consultants. The number of rights outstanding at any time is not to exceed 6% of the total number of trust units outstanding. At December 31 of each year, all vested rights are automatically cancelled and, if applicable, paid out in cash. Compensation is calculated as the number of vested rights multiplied by the total of the market appreciation (over the price at the date of grant) and associated distributions of a trust unit for that period. For rights vesting in 2007 and 2008, a tax factor of 1.333 will then be applied to determine the amount to be paid. Commencing 2009, no tax factor will be applied to determine the amount paid.
Based on the five day weighted average trading price of the trust units for the period ended September 30, 2007, compensation costs related to 4.2 million non-vested rights (4% of the total number of trust units outstanding), with an average grant price of $21.93, are $202,000. The Trust records a non-cash provision for future compensation expense over the life of the rights. The cumulative provision is $640,000.
Capital Expenditures
Net capital expenditures for the third quarter of 2007 totaled $42.6 million. Exploration and development related activity represented $31.5 million or 74% of the total, while expenditures on facilities, gathering systems and equipment totaled $10.1 million or 24% of the total. The following table summarizes capital expenditures for the quarter.
-------------------------------------------------------------------------
Three Months ended Nine Months ended
Sep 30 Sep 30
($000) 2007 2006 2007 2006
-------------------------------------------------------------------------
Land 555 575 997 13,253
Seismic 477 790 1,322 8,361
Drilling - Exploratory &
Development 31,455 51,489 67,166 204,808
Production Equipment, Facilities
& Pipelines 10,096 18,351 16,516 56,925
Acquisitions & Dispositions - - - -
Office Equipment 15 18 23 166
-------------------------------------------------------------------------
Total Capital Expenditures 42,598 71,223 86,024 283,513
-------------------------------------------------------------------------
Distributions
-------------------------------------------------------------------------
Three Months ended Nine Months ended
Sep 30 Sep 30
2007 2006 2007 2006
-------------------------------------------------------------------------
Funds from operations ($000) 62,938 72,360 210,647 227,485
Total distributions ($000) 44,399 44,111 133,148 129,549
Total distributions per unit ($) 0.42 0.42 1.26 1.24
Payout ratio (%) 71 61 63 57
Cash distributions ($000) (net
of DRIP) 44,399 41,019 133,148 113,999
Payout ratio (%) 71 57 63 50
-------------------------------------------------------------------------
Peyto's strategy is to maintain a sustainable distribution that is well balanced with its business needs and high quality assets, while offering the prospect of growth into the future. The Board of Directors is prepared to adjust the payout levels to achieve the desired distributions while maintaining an appropriate capital structure. For Canadian income tax purposes distributions made are considered a combination of income and return of capital. The portion that is return of capital reduces the adjusted cost base of the units.
Accumulated Earnings and Distributions
-------------------------------------------------------------------------
Three Months ended Nine Months ended
Sep 30 Sep 30
($000) 2007 2006 2007 2006
-------------------------------------------------------------------------
Opening accumulated earnings 626,862 437,987 531,154 335,926
Net earnings for the period 39,886 46,155 135,594 148,216
-------------------------------------------------------------------------
Total accumulated earnings 666,748 484,142 666,748 484,142
Total accumulated distributions (578,066) (400,712) (578,066) (400,712)
-------------------------------------------------------------------------
Accumulated earnings per
Balance Sheet 88,682 83,430 88,682 83,430
-------------------------------------------------------------------------
Since inception, Peyto has accumulated earnings of $666.7 million and
distributed $578.1 million to unitholders.
Contractual Obligations
The Trust is committed to payments under operating leases for office space
as follows:
-------------------------------------------------------------------------
($000) $
-------------------------------------------------------------------------
2007 238
2008 1,096
2009 1,097
2010 1,097
2011 1,097
-------------------------------------------------------------------------
4,625
-------------------------------------------------------------------------
-------------------------------------------------------------------------
RELATED PARTY TRANSACTIONS
An officer of the Trust is a partner of a law firm that provides legal services to the Trust. The fees charged are based on standard rates and time spent on matters pertaining to the Trust and its subsidiaries.
INCOME TAXES
The following sets out a general discussion of the Canadian and US tax consequences of holding Peyto units as capital property. The summary is not exhaustive in nature and is not intended to provide legal or tax advice. Unitholders or potential Unitholders should consult their own legal or tax advisors as to their particular tax consequences.
Canadian Taxpayers
The Trust qualifies as a mutual fund trust under the Income Tax Act (Canada) and, accordingly, Trust units are qualified investments for RRSPs, RRIFs, RESPs and DPSPs. Each year, the Trust is required to file an income tax return and any taxable income of the Trust is allocated to unitholders.
Unitholders are required to include in computing income their pro-rata share of any taxable income earned by the Trust in that year. An investor's adjusted cost base (ACB) in a trust unit equals the purchase price of the unit less any non-taxable cash distributions received from the date of acquisition. To the extent the unitholders' ACB is reduced below zero, such amount will be deemed to be a capital gain to the unitholder and the unitholders' ACB will be brought to nil.
During the third quarter of 2007, the Trust paid distributions to the unitholders in the amount of $44.4 million (2006 - $44.1 million) in accordance with the following schedule:
Production Period Record Date Distribution Date Per Unit ------------------------------------------------------------------------- January 2007 January 31, 2007 February 15, 2007 $0.14 February 2007 February 28, 2007 March 15, 2007 $0.14 March 2007 March 31, 2007 April 13, 2007 $0.14 April 2007 April 30, 2007 May 15, 2007 $0.14 May 2007 May 31, 2007 June 15, 2007 $0.14 June 2007 June 30, 2007 July 13, 2007 $0.14 July 2007 July 31, 2007 August 15, 2007 $0.14 August 2007 August 31, 2007 September 14, 2007 $0.14 September 2007 September 30, 2007 October 15, 2007 $0.14
US Taxpayers
US unitholders who receive cash distributions are subject to a 15 percent Canadian withholding tax, applied to the taxable portion of the distributions as computed under Canadian tax law. US taxpayers may be eligible for a foreign tax credit with respect to Canadian withholding taxes paid.
The taxable portion of the cash distributions, if any, is determined by the Trust in relation to its current and accumulated earnings and profit using US tax principles. The taxable portion so determined, is considered to be a dividend for US tax purposes.
The non-taxable portion of the cash distributions is a return of the cost (or other basis). The cost (or other basis) is reduced by this amount for computing any gain or loss from disposition. However, if the full amount of the cost (or other basis) has been recovered, any further non-taxable distributions should be reported as a gain.
A bill was introduced into United States Congress on March 23, 2007 that could deny qualified dividend income treatment to the distributions made by the Trust to its U.S. unitholders. The bill is in the first step of the legislative process and it is uncertain whether it will eventually be passed into law in its current form. If the bill is passed in its current form, distributions received by U.S. unitholders would no longer qualify for the 15 per cent qualified dividend tax rate.
US unitholders are advised to seek legal or tax advice from their professional advisors.
RISK MANAGEMENT
Investors who purchase units are participating in the net funds from operations from a portfolio of western Canadian crude oil and natural gas producing properties. As such, the funds from operations paid to investors and the value of the units are subject to numerous risks inherent in the oil and natural gas industry.
Expected funds from operations depend largely on the volume of petroleum and natural gas production and the price received for such production, along with the associated costs. The price received for oil depends on a number of factors, including West Texas Intermediate oil prices, Canadian/US currency exchange rates, quality differentials and Edmonton par oil prices. The price received for natural gas production is primarily dependent on current Alberta market prices. Peyto's marketing and risk management strategy is designed to smooth out short term fluctuations in the price of both natural gas and natural gas liquids through future sales. It is meant to be methodical and consistent, and to avoid speculation.
Although Peyto's focus is on internally generated drilling programs, any acquisition of oil and natural gas assets depends on assessment of value at the time of acquisition. Incorrect assessments of value can adversely affect distributions to unitholders and the value of the units. Peyto employs experienced staff on its team and performs appropriate levels of due diligence on the analysis of acquisition targets, including a detailed examination of reserve reports; if appropriate, re-engineering of reserves for a large portion of the properties to ensure the results are consistent; site examinations of facilities for environmental liabilities; detailed examination of balance sheet accounts; review of contracts; review of prior year tax returns and modeling of the acquisition to attempt to ensure accretive results to the unitholders.
Inherent in development of the existing oil and gas reserves are the risks, among others, of drilling dry holes, encountering production or drilling difficulties or experiencing high decline rates in producing wells. To minimize these risks, Peyto employs experienced staff to evaluate and operate wells and utilizes appropriate technology in its operations. In addition, prudent work practices and procedures, safety programs and risk management principles, including insurance coverage protect the Trust against certain potential losses.
The value of Peyto's units is based on, among other things, the underlying value of the oil and natural gas reserves. Geological and operational risks can affect the quantity and quality of reserves and the cost of ultimately recovering those reserves. Lower oil and gas prices increase the risk of write-downs on our oil and gas property investments. In order to mitigate this risk, proven and probable oil and gas reserves are evaluated each year by a firm of independent reservoir engineers. The Reserves Committee of the Board of Directors reviews and approves the reserve report.
Access to markets may be restricted at times by pipeline or processing capacity. These risks are minimized by controlling as much of the processing and transportation activities as possible and ensuring transportation and processing contracts are in place with reliable cost efficient counter-parties.
The petroleum and natural gas industry is subject to extensive controls, regulatory policies and income and resource taxes imposed by various levels of government. These regulations, controls and taxation policies are amended from time to time. Peyto has no control over the level of government intervention or taxation in the petroleum and natural gas industry. The Trust operates in such a manner to ensure, to the best of its knowledge that it is in compliance with all applicable regulations and is able to respond to changes as they occur. Crown royalty rates assessed on the Trust's oil and natural gas production are set by the government of the Province of Alberta. These rates are subject to review and modification from time to time.
The petroleum and natural gas industry is subject to both environmental regulations and an increased environmental awareness. Environment risks have been reviewed and to the best of Peyto's knowledge, the Trust is in compliance with environmental legislation. Currently, there is no current material impact on Peyto's operations.
Peyto is subject to financial market risk. In order to maintain substantial rates of growth, the Trust must continue reinvesting in, drilling for or acquiring petroleum and natural gas. The capital expenditure program is funded primarily through funds from operations, debt and equity.
DISCLOSURE CONTROLS AND PROCEDURES
Disclosure controls and procedures are designed to provide reasonable assurance that all relevant information is gathered and reported to senior management, including the Chief Executive Officer ("CEO") and Vice President, Finance ("VPF"), on a timely basis so that appropriate decisions can be made regarding public disclosure.
As of the end of the period covered by this report, Peyto's management evaluated the effectiveness of the design and operation of its disclosure controls and procedures, under the supervision of, and with the participation of the CEO and VPF. Based on this evaluation, the CEO and VPF have concluded that Peyto's disclosure controls and procedures, as defined in Multilateral Instrument 52-109, Certification of Disclosure in Issuers Annual and Interim Filings are effective to ensure that material information relating to Peyto is made known to management on a timely basis and is included in this report.
Internal Controls Update
Peyto is required to comply with Multilateral Instrument 52-109 "Certification of Disclosure in Issuers' Annual and Interim Filings". The 2007 certificate requires that the Trust disclose in the interim MD&A any changes in the Trust's internal control over financial reporting that occurred during the period that has materially affected, or is reasonably likely to materially affect the Trust's internal control over financial reporting. The Trust confirms that no such changes were made to the internal controls over financial reporting during the first nine months of 2007.
CRITICAL ACCOUNTING ESTIMATES
Reserve Estimates
Estimates of oil and natural gas reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent to the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is an analytical process of estimating underground accumulations of oil and natural gas that can be difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and natural gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future oil and natural gas prices, future royalties and operating costs, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk recovery, and estimates of the future net cash flows expected there from may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of the Trust's oil and natural gas properties and the rate of depletion of the oil and natural gas properties as well as the calculation of the reserve value based compensation. Actual production, revenues and expenditures with respect to the Trust's reserves will likely vary from estimates, and such variances may be material.
The Trust's estimated quantities of proved and probable reserves at December 31, 2006 were audited by independent petroleum engineers Paddock Lindstrom & Associates Ltd. Paddock has been evaluating reserves in Peyto's areas of operation and for Peyto for 8 consecutive years.
Depletion and Depreciation Estimate
The full cost method of accounting for petroleum and natural gas operations is followed whereby all costs of exploring for and developing petroleum and natural gas reserves are capitalized. Such costs include land acquisition costs, geological and geophysical costs, carrying charges on non producing properties, costs of drilling both productive and non productive wells and overhead charges directly related to acquisition, exploration and development activities.
All costs of exploring for and developing petroleum and natural gas reserves, together with the costs of production equipment, are depleted and depreciated on the unit of production method based on estimated gross proven reserves. Petroleum and natural gas reserves and production are converted into equivalent units based upon estimated relative energy content (6 mcf to 1 barrel of oil).
Costs of acquiring unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed periodically to ascertain whether impairment has occurred. When proven reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations.
Full Cost Accounting Ceiling Test
The carrying value of property, plant and equipment is reviewed at least annually for impairment. Impairment occurs when the carrying value of the assets is not recoverable by the future undiscounted cash flows. The ceiling test is based on estimates of proved reserves, production rates, estimated future petroleum and natural gas prices and costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the impact on the financial statements could be material. Any impairment would be charged as additional depletion and depreciation expense.
Asset Retirement Obligation
The asset retirement obligation is estimated based on existing laws, contracts or other policies. The fair value of the obligation is based on estimated future costs for abandonment and reclamation discounted at a credit adjusted risk free rate. The liability is adjusted each reporting period to reflect the passage of time and for revisions to the estimated future cash flows, with the accretion charged to earnings. By their nature, these estimates are subject to measurement uncertainty and the impact on the financial statements could be material.
Future Market Performance Based Compensation
The provision for future market based compensation is estimated based on current market conditions, distribution history and on the assumption that all outstanding rights will be paid out according to the vesting schedule. The conditions at the time of vesting could vary significantly from the current conditions and may have a material effect on the calculation.
Reserve Value Performance Based Compensation
The reserve value based compensation is calculated using the 2006 year end independent reserves evaluation which was completed in January 2007. A quarterly provision for the reserve value based compensation is calculated using estimated proved producing reserve additions adjusted for changes in debt, equity and distributions. Actual proved producing reserves additions and forecasted commodity prices could vary significantly from those estimated and may have a material effect on the calculation.
Income Taxes
The determination of the Trust's income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded.
Effect of Change in Accounting Policies
Effective January 1, 2007, the Trust adopted the revised recommendations of CICA section 1506, "Accounting Changes." The new recommendations permit voluntary changes in accounting policy only if they result in financial statements which provide more reliable and relevant information. Accounting policy changes are applied retrospectively unless it is impractical to determine the period or cumulative impact of the change. Corrections of prior period errors are applied retrospectively and changes in accounting estimates are applied prospectively by including these changes in earnings. The guidance was effective for all changes in accounting polices, changes in accounting estimates and corrections of prior period errors initiated in periods beginning on or after January 1, 2007. When the Trust has not applied a new primary source of GAAP that has been issued, but is not effective, the Trust will disclose the fact along with information relevant to assessing the possible impact that application of the new primary source of GAAP will have on the financial statements in the period of initial application.
As of January 1, 2008, the Trust will be required to adopt two new CICA Handbook Sections, Section 3862 "Financial Instruments - Disclosures" and Section 3863 "Financial Instruments - Presentation" which will replace current Section 3861. The new standards require disclosure of the significance of financial instruments to an entity's financial statements, the risks associated with the financial instruments, and how those risks are managed. The new presentation standard essentially carries forward the current presentation requirements. The Trust is assessing the impact of these new standards on its consolidated financial statements and anticipates the main impact will be in terms of additional disclosures required.
As of January 1, 2008, the Trust will be required to adopt CICA handbook Section 1535 "Capital Disclosures", which requires entities to disclose their objectives, policies and processes for management of capital, and in addition, whether the entity has complied with any externally imposed capital requirements. The Trust is assessing the impact of this new standard on its consolidated financial statements and anticipates the main impact will be in terms of additional disclosures required.
ADDITIONAL INFORMATION
Additional information relating to Peyto Energy Trust can be found on SEDAR at www.sedar.com and www.peyto.com.
Quarterly information
-------------------------------------------------------------------------
2007 2006
Q3 Q2 Q1 Q4 Q3
-------------------------------------------------------------------------
Operations
Production
Natural gas
(mcf/d) 97,000 101,812 106,183 112,296 115,304
Oil & NGLs
(bbl/d) 3,573 3,540 3,607 3,834 4,205
Barrels of
oil
equivalent
(boe/d @
6:1) 19,740 20,509 21,305 22,550 23,422
Average
product
prices
Natural gas
($/mcf) 7.61 8.59 9.77 8.84 7.81
Oil &
natural gas
liquids
($/bbl) 70.51 65.65 59.79 54.89 64.50
$/BOE
Average sale
price
($/boe) 50.15 53.98 58.84 53.35 50.05
Average
royalties
paid ($/boe) 8.52 9.50 10.59 9.29 10.99
Average
operating
expenses
($/boe) 2.48 2.70 2.84 2.69 1.90
Average
transportation
costs
($/boe) 0.58 0.57 0.59 0.52 0.58
Field netback
($/boe) 38.57 41.21 44.82 40.85 36.58
General &
administrative
expense
($/boe) 0.82 1.10 0.98 0.85 0.55
Interest
expense
($/boe) 3.10 2.95 2.96 2.72 2.52
Cash netback
($/boe) 34.65 37.16 40.88 37.28 33.51
Financial ($000
except per
unit)
Revenue 91,070 100,750 112,825 110,696 107,844
Royalties (net
of ARTC) 15,481 17,734 20,326 19,271 23,680
Funds from
operations 62,938 69,345 78,364 77,360 72,360
Funds from
operations
per unit 0.60 0.66 0.74 0.74 0.69
Total
distributions 44,399 44,399 44,350 44,206 44,111
Total
distributions
per unit 0.42 0.42 0.42 0.42 0.42
Payout ratio 71% 64% 57% 57% 61%
Cash
distributions
(net of DRIP) 44,399 44,399 44,350 44,206 41,019
Payout ratio 71% 64% 57% 57% 57%
Earnings 39,886 38,825 56,833 47,012 46,155
Earnings per
diluted unit 0.37 0.37 0.54 0.44 0.44
Capital
expenditures 42,598 12,949 30,478 28,413 71,223
Weighted
average
trust units
out-
standing 105,712,364 105,712,364 105,542,484 105,251,394 104,924,702
Peyto Energy Trust
Consolidated Balance Sheets
($000)
(unaudited)
September 30, December 31,
2007 2006
$ $
-------------------------------------------------------------------------
Assets
Current
Cash 4,467 10,806
Accounts receivable (Note 10) 42,746 53,418
Financial derivative assets (Note 10) 18,457 -
Due from private placements - 5,042
Prepaid expenses and deposits 3,909 2,681
-------------------------------------------------------------------------
69,579 71,947
Property, plant and equipment (Note 3) 1,094,982 1,064,753
-------------------------------------------------------------------------
1,164,561 1,136,700
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities and Unitholders' Equity
Current
Accounts payable and accrued liabilities 65,648 70,836
Cash distributions payable 14,800 14,735
Provision for future performance based
compensation 68 -
-------------------------------------------------------------------------
80,516 85,571
-------------------------------------------------------------------------
Long-term debt (Note 4) 410,000 420,000
Provision for future performance based
compensation 572 -
Asset retirement obligations 6,610 5,767
Future income taxes (Note 5) 159,119 135,650
-------------------------------------------------------------------------
576,301 561,417
-------------------------------------------------------------------------
Unitholders' equity
Unitholders' capital (Note 6) 406,301 398,434
Units to be issued (Note 6) - 5,042
Accumulated earnings 88,682 86,236
Accumulated other comprehensive income
(Notes 2, 10) 12,761 -
-------------------------------------------------------------------------
507,744 489,712
-------------------------------------------------------------------------
1,164,561 1,136,700
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
On behalf of the Board:
(signed) "Michael MacBean" (signed) "Darren Gee"
Director Director
Peyto Energy Trust
Consolidated Statements of Earnings
($000 except per unit amounts)
(unaudited)
Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
$ $ $ $
-------------------------------------------------------------------------
Revenue
Oil & gas sales 91,070 107,844 304,646 328,313
Royalties (net of ARTC) (15,481) (23,680) (53,541) (69,175)
-------------------------------------------------------------------------
Petroleum and natural gas sales,
net 75,589 84,164 251,105 259,138
-------------------------------------------------------------------------
Expenses
Operating (Note 8) 4,500 4,084 14,976 12,465
Transportation 1,045 1,256 3,245 3,767
General and administrative (Note 9) 1,483 1,194 5,428 2,209
Future performance based
compensation provision 202 (2,005) 640 192
Interest on long term debt 5,623 5,432 16,809 12,374
Depletion, depreciation and
accretion (Note 3) 18,042 20,389 56,639 60,701
-------------------------------------------------------------------------
30,895 30,350 97,737 91,708
-------------------------------------------------------------------------
Earnings before taxes 44,694 53,814 153,368 167,430
-------------------------------------------------------------------------
Taxes
Future income tax expense (Note 5) 4,808 7,821 17,774 19,376
Capital tax expense - (162) - (162)
-------------------------------------------------------------------------
7,659 19,214
-------------------------------------------------------------------------
Net earnings for the period 39,886 46,155 135,594 148,216
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per unit (Note 6)
Basic 0.37 0.44 1.28 1.42
Diluted 0.37 0.44 1.28 1.42
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
Peyto Energy Trust
Consolidated Statements of Comprehensive Income
($000 except per unit amounts)
(unaudited)
Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
$ $ $ $
-------------------------------------------------------------------------
Net earnings for the period 39,886 46,155 135,594 148,216
Other comprehensive income (loss)
Change in unrealized gain on cash
flow hedges, net of tax 5,177 - 11,108 -
Realized (gain) loss on cash flow
hedges, net of tax (7,571) - (21,788) -
-------------------------------------------------------------------------
Comprehensive Income (Note 2) 37,492 46,155 124,914 148,216
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
Peyto Energy Trust
Consolidated Statements of Accumulated Earnings and Accumulated Other
Comprehensive Income
($000)
(unaudited)
Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
$ $ $ $
-------------------------------------------------------------------------
Accumulated earnings, beginning of
period 93,195 81,386 86,235 64,763
Net earnings for the period 39,886 46,155 135,594 148,216
Distributions (Note 7) (44,399) (44,111) (133,149) (129,549)
-------------------------------------------------------------------------
Accumulated earnings, end of
period 88,682 83,430 88,682 83,430
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Accumulated other comprehensive
income, beginning of period 15,155 - - -
Adoption of financial instruments,
net of tax (Notes 2,10) - - 23,441 -
Other comprehensive income
(Notes 2,10) (2,394) - (10,680) -
-------------------------------------------------------------------------
Accumulated other comprehensive
income, end of period 12,761 - 12,761 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
Peyto Energy Trust
Consolidated Statements of Cash Flows
($000)
(unaudited)
Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
$ $ $ $
-------------------------------------------------------------------------
Cash provided by (used in)
Operating Activities
Net earnings for the period 39,886 46,155 135,594 148,216
Items not requiring cash:
Future income tax expense 4,808 7,821 17,774 19,376
Depletion, depreciation and
accretion 18,042 20,389 56,639 60,701
Change in non-cash working capital
related to operating activities 10,163 (6,166) 9,167 (34,884)
-------------------------------------------------------------------------
72,899 68,199 219,174 193,409
-------------------------------------------------------------------------
Financing Activities
Issue of trust units, net of costs
and DRIP - 8,748 2,825 25,815
Cash distribution paid (net of
DRIP) (44,399) (41,019) (133,149) (113,999)
Increase (decrease) in bank debt - 10,000 (10,000) 220,000
Change in non-cash working capital
related to financing activities - 1,390 5,107 30,656
-------------------------------------------------------------------------
(44,399) (20,881) (135,217) 162,472
-------------------------------------------------------------------------
Investing Activities
Additions to property, plant and
equipment (42,598) (71,223) (86,024) (283,513)
Change in non-cash working
capital related to investing
activities 7,341 26,353 (4,272) (66,081)
-------------------------------------------------------------------------
(35,257) (44,870) (90,296) (349,594)
-------------------------------------------------------------------------
Net increase (decrease) in cash (6,757) 2,448 (6,339) 6,287
Cash, beginning of period
(Note 11) 11,224 3,839 10,806 -
-------------------------------------------------------------------------
Cash, end of period 4,467 6,287 4,467 6,287
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
Peyto Energy Trust
Notes to Consolidated Financial Statements
(unaudited)
September 30, 2007 and 2006
1. Summary of Significant Accounting Policies
The unaudited interim consolidated financial statements of Peyto
Energy Trust (the "Trust") follow the same accounting policies as the
most recent annual audited consolidated financial statements except
as disclosed in Note 2. 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 2006 audited
consolidated financial statements.
These financial statements include the accounts of Peyto Energy Trust
and its wholly owned subsidiaries, Peyto Exploration & Development
Corp. and Peyto Operating Trust.
2. Changes in Accounting Policies
Effective January 1, 2007, the Trust adopted the Canadian Institute
of Chartered Accountants ("CICA") Section 3855, "Financial
Instruments - Recognition and Measurement," Section 3865, "Hedges,"
Section 1530, "Comprehensive Income" and Section 3861, "Financial
Instruments - Disclosure and Presentation." The Trust has adopted
these standards retroactively without restatement and the comparative
interim consolidated financial statements have not been restated.
Transition amounts have been recorded in retained earnings or
accumulated other comprehensive income ("AOCI"). Accumulated other
comprehensive income is included on the balance sheet as a separate
component of Unitholders' equity, and includes the effective gains
and losses on derivative instruments designated as cash flow hedges.
a) Financial Instruments
All financial instruments must initially be recognized at fair value
on the balance sheet. The Trust has classified each financial
instrument into the following categories: "held for trading" and
"available for sale" financial assets and financial liabilities;
"loans or receivables"; and "other financial liabilities". Subsequent
measurement of the financial instruments is based on their
classification. Unrealized gains and losses on held for trading
financial instruments are recognized in earnings. Gains and losses on
available for sale financial assets are recognized in other
comprehensive income and are transferred to earnings when the asset
is settled. The other categories of financial instruments are
recognized at amortized cost using the effective interest rate
method.
b) Derivative Instruments and Hedging Activities
Derivative instruments are utilized by the Trust to manage market
risk against the volatility in commodity prices. The Trust's policy
is not to utilize derivative instruments for speculative purposes.
The Trust has chosen to designate its existing derivative instruments
as cash flow hedges. The Trust assesses on an ongoing basis, whether
the derivatives that are used as cash flow hedges are highly
effective in offsetting changes in cash flows of hedged items. All
derivative instruments are recorded on the balance sheet at fair
value in either accounts receivable or accrued liabilities. The
effective portion of the gains and losses is recorded in other
comprehensive income until the hedged transaction is recognized in
earnings. When the earnings impact of the underlying hedged
transaction is recognized in the consolidated statement of earnings,
the fair value of the associated cash flow hedge is reclassified from
other comprehensive income into earnings. Any hedge ineffectiveness
is immediately recognized in earnings. The fair values of forward
contracts are based on forward market prices.
c) Embedded Derivatives
An embedded derivative is a component of a contract that causes some
of the cash flows of the combined instrument to vary in a way similar
to a stand-alone derivative. This causes some or all of the cash
flows that otherwise would be required by the contract to be modified
according to a specified variable, such as interest rate, financial
instrument price, commodity price, foreign exchange rate, a credit
rating or credit index, or other variables. The Trust has no
contracts containing embedded derivatives.
d) Comprehensive Income
Comprehensive income consists of net earnings and other comprehensive
income ("OCI"). OCI comprises the change in the fair value of the
effective portion of the derivatives used as hedging items in a cash
flow hedge. "Accumulated other comprehensive income" is a new equity
category comprised of the cumulative amounts of OCI.
Effect of Change in Accounting Policies
Effective January 1, 2007, the Trust adopted the revised
recommendations of CICA section 1506, "Accounting Changes." The new
recommendations permit voluntary changes in accounting policy only if
they result in financial statements which provide more reliable and
relevant information. Accounting policy changes are applied
retrospectively unless it is impractical to determine the period or
cumulative impact of the change. Corrections of prior period errors
are applied retrospectively and changes in accounting estimates are
applied prospectively by including these changes in earnings. The
guidance was effective for all changes in accounting polices, changes
in accounting estimates and corrections of prior period errors
initiated in periods beginning on or after January 1, 2007. When the
Trust has not applied a new primary source of GAAP that has been
issued, but is not effective, the Trust will disclose the fact along
with information relevant to assessing the possible impact that
application of the new primary source of GAAP will have on the
financial statements in the period of initial application.
As of January 1, 2008, the Trust will be required to adopt two new
CICA Handbook Sections, Section 3862 "Financial Instruments -
Disclosures" and Section 3863 "Financial Instruments - Presentation"
which will replace current Section 3861. The new standards require
disclosure of the significance of financial instruments to an
entity's financial statements, the risks associated with the
financial instruments, and how those risks are managed. The new
presentation standard essentially carries forward the current
presentation requirements. The Trust is assessing the impact of these
new standards on its consolidated financial statements and
anticipates the main impact will be in terms of additional
disclosures required.
As of January 1, 2008, the Trust will be required to adopt CICA
handbook Section 1535 "Capital Disclosures:, which requires entities
to disclose their objectives, policies and processes for management
of capital, and in addition, whether the entity has complied with any
externally imposed capital requirements. The Trust is assessing the
impact of this new standard on its consolidated financial statements
and anticipates the main impact will be in terms of additional
disclosures required.
3. Property, Plant and Equipment
September 30, December 31,
2007 2006
($000) $ $
---------------------------------------------------------------------
Property, plant and equipment 1,375,070 1,288,616
Accumulated depletion and depreciation (280,088) (223,863)
---------------------------------------------------------------------
1,094,982 1,064,753
---------------------------------------------------------------------
---------------------------------------------------------------------
At September 30, 2007 costs of $38.6 million (September 30, 2006 -
$39.0 million) related to undeveloped land have been excluded from
the depletion and depreciation calculation.
4. Long-Term Debt
The Trust has a syndicated $525 million extendible revolving credit
facility. The facility is made up of a $20 million working capital
sub-tranche and a $505 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 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 earnings before interest, taxes, depreciation, depletion and
amortization (EBITDA) ratio that range from prime to prime plus 0.75%
for debt to EBITDA 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.
5. Income Taxes
On June 22, 2007, Bill C-52 ("Bill") was enacted for Canadian GAAP.
The Bill enacts the October 31, 2006 proposals to impose a new tax on
distributions from flow-through entities, including publicly traded
income trusts. This has not resulted in any change in the
consolidated future income tax calculation.
6. Unitholders' Capital
Authorized: Unlimited number of voting trust units
Issued and Outstanding
Trust Units (no par value) Number of Amount
($000) Shares/Units $
---------------------------------------------------------------------
Balance, December 31, 2005 102,333,847 328,736
Trust units issued by private placement 1,393,940 34,378
Trust units issued pursuant to DRIP 690,387 16,301
Trust units issued pursuant to OTUPP 833,220 19,019
---------------------------------------------------------------------
Balance, December 31, 2006 105,251,394 398,434
Trust units issued by private placement 460,970 7,867
---------------------------------------------------------------------
Balance, September 30, 2007 105,712,364 406,301
---------------------------------------------------------------------
---------------------------------------------------------------------
Units to be Issued
On March 2, 2005, Peyto implemented a Distribution Reinvestment Plan
("DRIP"). On November 21, 2005 the DRIP plan was amended to
incorporate an Optional Trust Unit Purchase Plan ("OTUPP") which
provides unitholders enrolled in the DRIP with the opportunity to
purchase additional trust units from treasury subject to certain
limitations, using the same pricing as the DRIP. Both the DRIP and
OTUPP were suspended August 31, 2006.
Per Unit Amounts
Earnings per unit have been calculated based upon the weighted
average number of units outstanding for the three months ended
September 30, 2007 of 105,712,364 (2006 - 104,924,702) and for the
nine months ended September 30, 2007 of 105,656,359 (2006 -
104,554,325). There are no dilutive instruments outstanding.
7. Accumulated Distributions
The Trust paid total distributions to the unitholders in the
aggregate amount of $44.4 million in the three months ended
September 30, 2007 of which all was settled in cash (2006 - total
$44.1 million; cash $41.0 million and DRIP $3.1 million) and
$133.1 million cash for the nine months ended September 30, 2007
(2006 - total $129.5 million; cash $114.0 million and DRIP
$15.5 million) in accordance with the following schedule:
Distribution Per
Production Period Record Date Date Unit
---------------------------------------------------------------------
January 2007 January 31, 2007 February 15, 2007 $0.14
February 2007 February 28, 2007 March 15, 2007 $0.14
March 2007 March 31, 2007 April 13, 2007 $0.14
April 2007 April 30, 2007 May 15, 2007 $0.14
May 2007 May 31, 2007 June 15, 2007 $0.14
June 2007 June 30, 2007 July 13, 2007 $0.14
July 2007 July 31, 2007 August 15, 2007 $0.14
August 2007 August 31, 2007 September 14, 2007 $0.14
September 2007 September 30, 2007 October 15, 2007 $0.14
8. Operating Expenses
The Trust's operating expenses include all costs with respect to
day-to-day well and facility operations. Processing and gathering
income related to joint venture and third party natural gas reduces
operating expenses.
Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
($000) $ $ $ $
---------------------------------------------------------------------
Field expenses 6,476 6,245 21,297 18,404
Processing and gathering
income (1,976) (2,161) (6,321) (5,939)
---------------------------------------------------------------------
Total operating costs 4,500 4,084 14,976 12,465
---------------------------------------------------------------------
---------------------------------------------------------------------
9. General and Administrative Expenses
General and administrative expenses are reduced by operating and
capital overhead recoveries from operated properties.
Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
($000) $ $ $ $
---------------------------------------------------------------------
G&A expenses 2,536 2,556 5,059 6,971
Overhead recoveries (1,053) (1,362) (2,167) (4,762)
---------------------------------------------------------------------
Net G&A expenses 1,483 1,194 5,428 2,209
---------------------------------------------------------------------
---------------------------------------------------------------------
10. Financial Instruments
As described in Note 2, on January 1, 2007, the Trust adopted the new
CICA requirements relating to financial instruments. The following
summarizes the retrospective without restatement adoption adjustments
that were required as at January 1, 2007.
December 31, January 1,
2006 Adoption 2007
($000) (As Reported) Adjustment (As Restated)
---------------------------------------------------------------------
Consolidated Balance Sheets
Assets
---------------------------------------------------------------------
Financial derivative
asset - 33,904 33,904
---------------------------------------------------------------------
Liabilities and
Unitholders' Equity
---------------------------------------------------------------------
Future income taxes 135,650 10,463 146,113
---------------------------------------------------------------------
Accumulated other
comprehensive income - 23,441 23,441
---------------------------------------------------------------------
Commodity Price Risk Management
The Trust is a party to certain off balance sheet derivative
financial instruments, including fixed price contracts. The Trust
enters into these contracts with well established counterparties for
the purpose of protecting a portion of its future earnings and cash
flows from operations from the volatility of petroleum and natural
gas 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, 2007 is as follows:
Weighted
Average
Crude Oil Daily Price
Period Hedged Type Volume (CAD)
---------------------------------------------------------------------
October 1 to December 31, 2007 Fixed price 200 bbl $77.51/bbl
October 1 to December 31, 2007 Fixed price 300 bbl $78.75/bbl
January 1 to March 31, 2008 Fixed price 200 bbl $78.55/bbl
January 1 to March 31, 2008 Fixed price 300 bbl $79.05/bbl
Weighted
Average
Natural Gas Daily Price
Period Hedged Type Volume (CAD)
---------------------------------------------------------------------
April 1 to October 31, 2007 Fixed price 5,000 GJ $8.60/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $7.50/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $7.25/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $7.51/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $7.50/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $7.60/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $7.60/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $7.80/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $7.50/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $7.70/GJ
April 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $8.35/GJ
April 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $8.90/GJ
Nov 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $8.85/GJ
Nov 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $9.06/GJ
Nov 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $9.10/GJ
Nov 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $8.55/GJ
Nov 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $6.40/GJ
April 1 to October 31, 2008 Fixed price 5,000 GJ $7.85/GJ
April 1 to October 31, 2008 Fixed price 5,000 GJ $6.60/GJ
As at September 30, 2007, the Trust had committed to the future sale
of 91,500 barrels of crude oil at an average price of $78.55 per
barrel and 9,320,000 gigajoules (GJ) of natural gas at an average
price of $8.05 per GJ or $9.42 per mcf based on the historical
heating value of Peyto's natural gas. Had these contracts been closed
on September 30, 2007, the Trust would have realized a gain in the
amount of $18.5 million. Subsequent to September 30, 2007 the Trust
entered into the following contracts:
Natural Gas Daily Price
Period Hedged Type Volume (CAD)
---------------------------------------------------------------------
Nov 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $6.30/GJ
Dec 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $6.70/GJ
April 1 to October 31, 2008 Fixed price 5,000 GJ $6.40/GJ
April 1, 2008 to March 31, 2009 Fixed price 5,000 GJ $6.82/GJ
Nov 1, 2008 to March 31, 2009 Fixed price 5,000 GJ $7.25/GJ
Nov 1, 2008 to March 31, 2009 Fixed price 5,000 GJ $7.50/GJ
Fair Values of Financial Assets and Liabilities
The Trust's financial instruments include accounts receivable,
financial derivative assets, current liabilities, provision for
future performance based compensation and long term debt. At
September 30, 2007, the carrying value of accounts receivable,
financial derivative assets, current liabilities and provision for
future performance based compensation approximate their fair value
due to their short term nature or method of determination. The
carrying value of the long term debt approximates its fair value due
to the floating rate of interest charged under the facilities.
Credit Risk
A substantial portion of the Trust's accounts receivable is with
petroleum and natural gas marketing entities. 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 significant individual accounts receivable at
September 30, 2007, approximately 62% was due from three companies
(September 30, 2006 - two companies, 59%). Of the Trust's revenue for
the nine months ended September 30, 2007, approximately 94% was
received from three companies (September 30, 2006 - two companies,
59%).
The Trust may be exposed to certain losses in the event of non-
performance by counter-parties to commodity price contracts. The
Trust mitigates this risk by entering into transactions with counter-
parties that have investment grade credit ratings.
Interest rate risk
The Trust is exposed to interest rate risk in relation to interest
expense on its revolving demand facility.
11. Supplemental Cash Flow Information
Three Months Ended Nine Months Ended
September 30 September 30
2007 2006 2007 2006
($000) $ $ $ $
---------------------------------------------------------------------
Cash interest paid during the
period 5,623 5,432 16,809 12,374
---------------------------------------------------------------------
---------------------------------------------------------------------
12. Contingencies and Commitments
a) Contingent Liability
From time to time, Peyto is the subject of litigation arising out of
its day-to-day operations. 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.
b) Commitments
The Trust is committed to payments under operating leases for office
space as follows:
---------------------------------------------------------------------
($000) $
---------------------------------------------------------------------
2007 238
2008 1,096
2009 1,097
2010 1,097
2011 1,097
---------------------------------------------------------------------
4,625
---------------------------------------------------------------------
---------------------------------------------------------------------
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 Kathy Turgeon
Operating Officer Vice-President, Finance
Ken Veres Stephen Chetner
Vice-President, Exploration Corporate Secretary
Directors
Ian Mottershead, Chairman
Rick Braund
Don Gray
Brian Davis
Michael MacBean
Darren Gee
Gregory Fletcher
Auditors
Deloitte & Touche LLP
Solicitors
Burnet, Duckworth & Palmer LLP
Bankers
Bank of Montreal
Union Bank of California
Royal Bank of Canada
BNP Paribas
Societe Generale
ATB Financial
Fortis Capital (Canada) Ltd.
Transfer Agent
Valiant Trust Company
Stock Listing Symbol: PEY.un
Toronto Stock Exchange
%SEDAR: 00019597E