SYMBOL: PEY.UN - TSX
CALGARY, March 5 /CNW/ - Peyto Energy Trust ("Peyto" or the "Trust") is a leader in the exploration and development of natural gas in western Canada. By design, the Trust's core areas are located in Alberta's premier gas exploration area, the Deep Basin. Peyto is known for high quality, sweet natural gas assets, low cost structure and an ability to profitably find and develop new natural gas reserves, year after year. This performance is evidenced by an annual and five year average return on equity of 41% and 46%, respectively. Peyto is proud to present the operating and financial results for the fourth quarter and 2007 fiscal year.
The following summarizes certain attributes of the Trust at year end.
- Long reserve life - Proved Producing 13 years, Total Proved 16 years,
Proved plus Probable 21 years
- High revenue natural gas - $47.48/boe before hedging, $53.56/boe
after hedging
- Low operating costs (including transportation) - $3.14/boe
- High operating netback - $41.06/boe
- Low base general and administrative costs - $0.94/boe
- High operatorship - over 95% of production
- Low cash distribution ratio - 64% of fourth quarter 2007 funds from
operations
- Low debt to funds from operations ratio - 1.65 times (net debt,
before provision for future performance based compensation, divided
by annualized fourth quarter 2007 funds from operations)
- Distribution growth - distributions have been increased 5 times,
never decreased, and are now 87% higher than when the Trust was
formed four and a half years ago
- Since inception, Peyto has raised a total of $406 million issuing
units from treasury, accumulated earnings of $740 million, and
distributed $622 million to unitholders.
- Transparent capital structure - no convertible debentures, no
exchangeable shares, no stock options, no warrants
The year 2007 was highlighted by improved efficiency and the successful
execution of a disciplined capital investment strategy. The following
summarizes certain performance highlights for the year.
- Value creation - invested $122 million in capital and created
$569 million of Proved Producing and $465 million of Proved plus
Probable undiscounted reserve value, translating into Net Present
Value ("NPV") recycle ratios (as defined herein) of 4.7 and 3.8,
respectively
- Net Asset value - the debt adjusted, NPV per unit of the Trust's
Total Proved and Proved plus Probable oil and gas assets, discounted
at 5%, was $23.80/unit and $30.77/unit, respectively in 2007
- Reserve growth per unit - Proved Producing reserves, grew 2% year
over year
- Reserve life - Proved Producing reserve life grew from 12 years in
2006 to 13 years in 2007, while Proved plus Probable reserve life
grew from 20 to 21 years
- Distributions per unit - increased by 1% from $1.66 in 2006 to $1.68
in 2007.
- Distribution life growth - increased from 23 years in 2006 to
24 years in 2007 (based on undiscounted Proved Producing NPV and as
defined herein)
- Annual production - decreased 10% from 22,873 boe/d in 2006 to
20,669 boe/d in 2007
- Annual production per unit(1) - decreased 10% year over year and
12% per debt adjusted unit
- Annual funds from operations per unit(1) - decreased 9% year over
year and 11% per debt adjusted unit
- Cost of new reserves (Finding, Development & Acquisition "FD&A") -
decreased 28% to $12.68/boe for Proved Producing, 52% to $9.42/boe
for Total Proved and 46% to $9.38/boe for Proved Plus Probable
(including change in Future Development Capital "FDC")
- Recycle ratio - Proved Producing 2.8, Total Proved 3.7, Proved Plus
Probable 3.7
- Reserve replacement - Proved Producing 125%, Total Proved 175%,
Proved Plus Probable 117%
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)
(1) Per unit results are adjusted for changes in net debt (including
future performance based compensation) and equity. Net debt is
converted to equity using the Dec 31 unit price of $16.90 for 2007
and $17.70 for 2006.
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3 Months Ended 12 Months Ended
Dec. 31 % Dec. 31 %
2007 2006 Change 2007 2006 Change
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Operations
Production
Natural gas
(mcf/d) 104,749 112,296 (7)% 102,418 112,751 (9)%
Oil & NGLs
(bbl/d) 3,675 3,834 (4)% 3,599 4,081 (12)%
Barrels of
oil equiv-
alent (boe/d
at 6:1) 21,134 22,550 (6)% 20,669 22,873 (10)%
Product prices
Natural gas
($/mcf) 7.67 8.84 (13)% 8.42 8.46 -
Oil & NGLs
($/bbl) 75.23 54.89 37% 67.88 61.00 11%
Operating
expenses
($/boe) 2.25 2.69 (16)% 2.57 2.16 19%
Transportation
($/boe) 0.54 0.52 4% 0.57 0.58 (2)%
Field netback
($/boe) 39.54 40.85 (3)% 41.06 39.25 5%
General &
administrative
expenses
($/boe) 0.87 0.85 2% 0.94 0.48 96%
Interest
expense
($/boe) 3.19 2.72 17% 3.05 2.16 41%
Financial
($000, except
per unit)
Revenue 99,387 110,696 (10)% 404,033 439,008 (8)%
Royalties
(net of ARTC) 17,080 19,271 (11)% 70,621 88,446 (20)%
Funds from
operations 68,976 77,360 (11)% 279,624 305,845 (9)%
Funds from
operations
per unit 0.65 0.74 (12)% 2.65 2.93 (10)%
Total
distributions 44,399 44,206 - 177,548 173,755 2%
Total
distributions
per unit 0.42 0.42 - 1.68 1.66 1%
Payout ratio 64 57 12% 63 57 11%
Cash
distributions
(net of DRIP) 44,399 44,206 - 177,548 158,204 12%
Payout ratio 64 57 12% 63 52 21%
Earnings 73,289 47,012 56% 208,884 195,228 7%
Earnings per
diluted unit 0.69 0.44 57% 1.98 1.86 6%
Capital
expenditures 35,546 28,413 25% 121,571 311,926 (61)%
Weighted
average
trust units
outstand-
ing 105,712,364 105,251,394 - 105,712,364 104,554,322 1%
As at December 31
Net debt
(before future
compensation
expense) 457,427 433,624 5%
Unitholders'
equity 528,992 489,712 8%
Total assets 1,192,232 1,136,700 5%
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Net Earnings 73,289 47,012 208,884 195,228
Items not
requiring cash:
Provision for
(recovery of)
performance
based
compensation (371) (10,340) 269 (10,149)
Future income
tax expense (30,226) 7,981 (12,453) 27,357
Depletion,
depreciation
and
accretion 19,151 20,397 75,791 81,098
Non-recurring
items:
Performance
based
compensation 7,133 12,310 7,133 12,310
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Funds from
operations(1) 68,976 77,360 279,624 305,845
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(1) Funds from operations - Management uses funds from operations to
analyze the operating performance of its energy assets. In order to
facilitate comparative analysis, funds from operations is defined
throughout this report as earnings before performance based
compensation, non-cash and non-recurring expenses. Peyto believes
that funds from operations is an important parameter to measure the
value of an asset when combined with reserve life. Funds from
operations is not a measure recognized by Canadian generally accepted
accounting principles ("GAAP") and does not have a standardized
meaning prescribed by GAAP. Therefore, funds from operations, as
defined by Peyto, may not be comparable to similar measures presented
by other issuers, and investors are cautioned that funds from
operations should not be construed as an alternative to net earnings,
cash flow from operating activities or other measures of financial
performance calculated in accordance with GAAP. Funds from operations
cannot be assured and future distributions may vary.
For some, Peyto's 2007 may seem rather unremarkable. Lower capital expenditures and reduced activity resulted in 39 net wells drilled in 2007, compared to 66 net wells the year before. Even though this reduced activity resulted in 125% of the annual produced reserves being replaced, total average production rate declined from 22,873 boe/d to 20,669 boe/d, from last year to this year. In addition, natural gas prices (AECO Monthly) were down 5% from $6.62/GJ in 2006 to $6.26/GJ in 2007. As was expected, however, the NPV of the reserve assets was relatively unchanged from the previous year.
What makes 2007 a remarkable year is the significant improvement in Peyto's operating efficiency. Finding, Development and Acquisition ("FD&A") costs for Proved Producing reserves dropped 28% to $12.68/boe while FD&A costs for Total Proved reserves were down 52% to $9.42/boe. This improved efficiency was not only evident in lower FD&A costs but also in increased operating margins, and it ultimately translates into increased returns for unitholders. It is Peyto's relentless focus on generating high rates of return that ensures operating efficiencies are retained when business conditions could cause them to be lost. The Peyto strategy has always been to invest capital into internally generated ideas for the exploration and development of new Deep Basin natural gas reserves. These investments have, throughout Peyto's nine year history, generated substantial returns for shareholders and unitholders alike. The following table highlights those returns.
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2003 2004 2005 2006 2007
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Return on Equity - ROE 51% 46% 51% 43% 41%
Return on Capital Employed - ROCE 18% 23% 29% 23% 20%
Operating Margin(1) 73% 72% 71% 75% 77%
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(1) Return on Equity is earnings for the period divided by average
unitholders equity
(2) Return on Capital Employed is earnings before interest and tax for
the period divided by total assets less current liabilities
(3) Operating Margin is operating netback divided by sales price in $/boe
The returns that were generated in 2007 were no different. They were partly due to newly found and developed reserves and partly due to increasing the value of the existing assets. For instance, a new pipeline contract for transportation of liquids has reduced the trucking costs and increased Peyto's product prices for the condensate and NGLs from the Oldman gas plant. This arrangement has increased the value of the existing reserves. In addition, Peyto's 100% owned and operated gas plants continue to generate third party midstream revenues that improve the return on those specific capital investments. Expertise among the Peyto team extends beyond the exploration and development of new reserves, to the optimization and value realization of the existing assets. In 2007, Peyto invested $122 million of capital, just 43% of total funds from operations, yet the value of the producing asset base (Proved Producing, Before Tax NPV, discounted at 5% "BT NPV5"per unit) grew by 2%.
Peyto's strategy of reduced activity and improved capital efficiency began in 2006 and was successfully executed throughout 2007. Retention of financial flexibility and sustainability of distributions were primary goals. Year end net debt of $457 million leaves close to $70 million of available bank lines. Monthly distributions of $0.14/unit have been maintained since their increase in February 2006. Also during that time period, base production decline rates have lessened, requiring less capital to offset them. This trend is expected to continue into the future, allowing more capital to effect growth in total production rates.
Since Peyto's inception, a total of $1.4 billion in capital has been invested to build an asset that is worth $3.7 billion ($3.3 billion after adjusting for debt, Proved plus Probable, BT NPV5). In doing so, Peyto utilized $406 million of unitholders equity but has already returned to unitholders that amount plus $216 million more.
------------------------------------------------------------------------- Funding Sources for Capital Since Inception (from 1998 to 2007) ($000) % of Total ------------------------------------------------------------------------- Cash flow from projects found and developed by Peyto 1,164,151 83% Net Equity (Equity issued of $406.3 million less Accumulated Distributions of $622.5 million) (216,165) (16)% Net Debt (year end 2007 excluding future performance-based compensation) 457,427 33% ------------------------------------------------------------------------- Total Capital Expenditures 1,405,413 100% ------------------------------------------------------------------------- -------------------------------------------------------------------------
As illustrated in the above table, cash flow generated from investments has played a dominant role, while net equity has played a relatively minor role in funding the capital expenditures since Peyto's inception nine years ago.
Capital Expenditures
Net capital expenditures for 2007 totaled $122 million, a decrease of 61% from 2006, continuing a strategy of reduced activity in response to service cost inflation. Substantially all of the capital was directed to well-related activity with 80% associated with drilling and completions and 18% associated with wellsite equipment and pipelines. One significant infrastructure investment during the year was a 15 km pipeline which connected gas reserves in the Chime area to Peyto's Kakwa gas plant resulting in reduced processing costs. Minor amounts were spent on land and seismic, reflective of an increased concentration of development activity. None of the 2007 capital was spent in the higher priced acquisition market. The following table summarizes capital expenditures for the year.
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2007 2006 Since Inception
Capital % of % of % of
Expenditures ($000) Total ($000) Total ($000) Total
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Land 984 - 13,253 4% 41,980 3%
Seismic 1,799 2% 8,944 3% 35,055 3%
Drilling &
Completion
- Exploratory &
Development 96,908 80% 227,585 73% 1,026,435 73%
Production
Equipment,
Facilities &
Pipelines 21,834 18% 61,961 20% 270,029 19%
Acquisitions &
Dispositions - - - - 30,856 2%
Office Equipment 46 - 183 - 1,086 -
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Total 121,571 100% 311,926 100% 1,405,441 100%
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During the year, 48 gross (39 net) gas wells were drilled, 76 gross (63 net) zones were completed and 67 gross (54 net) zones were brought on production. Reduced service costs and increased efficiency of operations is evidenced by comparing the total capital per net well, year by year. The total capital per net well in 2007 of $3.1 million represents a reduction of 34% from $4.7 million per net well in 2006. As in past years, the average depth of Peyto's new wells increased another 35m to 2,641m, as drilling prospects continue to evolve to include deeper Cretaceous zones. Most wells have at least two and sometimes three prospective gas bearing zones for development.
Reserves
During 2007, the Trust was again successful in adding high quality, long life reserves with the drill bit. The following table illustrates the change in reserve volumes and net present value of future cash flow, discounted at 5%, before income tax using forecast pricing.
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As at December 31
% Change
Per Unit
(NPV(5)
% debt
2007 2006 Change adjusted)
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Reserves
BOE 6:1 (mstb)
Proved Producing 99,226 97,181 2% 2%
Total Proved 124,328 118,681 5% 5%
Proved + Probable Additional 164,759 163,464 1% 1%
Net Present Value ($million)
Discounted at 5%
Proved Producing 2,515 2,462 2% 2%
Total Proved 2,966 2,869 3% 3%
Proved + Probable Additional 3,703 3,679 1% 0%
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Note: Based on the Paddock Lindstrom & Associates report effective
December 31, 2007. The Paddock Lindstrom and Associates Ltd. price
forecast is available at www.padlin.com. For more information on Peyto's
reserves, refer to the Press Release dated February 13, 2008 announcing
the 2007 Year End Reserve Report which is available on the website at
www.peyto.com . The complete statement of reserves data and required
reporting in compliance with NI 51-101 will be included in Peyto's Annual
Information Form to be released in March 2008.
Value Creation
Peyto's primary objective is to build upon the per unit value of its energy resources so that income delivered to unitholders can be sustained, and increased over time. Each year's investment success is quantified by measuring the value created during the year compared to the capital invested. This investment success is then used as justification for re-investment of unitholders' capital. At Peyto's request and for the benefit of unitholders, the independent engineers have run last year's Net Present Value (NPV), against this year's price forecast to eliminate the change in value attributable to commodity prices. This approach isolates the value created by the Peyto team from the value created by the change in commodity prices. In 2007, $569 million of Proved Producing and $465 million of Proved plus Probable undiscounted reserve value was created from $122 million in capital. Relative to the enterprise value, this amount of net value creation represents a significant growth rate. The following table, using forecast prices and costs as at December 31, 2007, breaks out the value created by Peyto's capital investments and reconciles the changes in debt adjusted NPV of future net revenues.
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Proven +
Proven Total Probable
Producing Proven Additional
($millions)
Discounted at 0% 5% 0% 5% 0% 5%
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Net Present Value at
Beginning of Year
($millions) $4,066 $2,029 $4,961 $2,435 $7,059 $3,245
Dec. 31, 2006 Evaluation
using PLA Jan. 1, 2007
price forecast,
debt adjusted
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Per Unit Outstanding
at Dec. 31, 2006
($/unit) $38.53 $19.22 $47.01 $23.08 $66.88 $30.75
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2007 sales (revenue
less royalties and
operating costs) ($310) ($310) ($310) ($310) ($310) ($310)
Net Change due to
price forecasts
(using PLA Jan 1,
2008 price forecast) ($82) ($50) ($94) ($64) ($92) ($86)
Net Change due to
discoveries
(additions,
extensions, transfers,
revisions) $569 $395 $675 $454 $465 $403
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Net Present Value at End
of Year ($millions) $4,243 $2,064 $5,232 $2,516 $7,122 $3,253
Dec. 31, 2007 Evaluation
using PLA Jan. 1, 2008
price forecast, debt
adjusted
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Per Unit Outstanding
at Dec. 31, 2007
($/unit) $40.14 $19.53 $49.49 $23.80 $67.37 $30.77
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Performance Measures
There are a number of performance measures that are used in the oil and gas industry in an attempt to evaluate how profitably capital has been invested. Peyto believes that the value analysis presented above is the best determination of profitability as it compares the value of what was created relative to what was invested, or what is termed, the NPV recycle ratio. This is because the NPV of an oil and gas asset takes into consideration the reserves, the production forecast, the future royalties and operating costs, future capital and the current commodity price outlook. In 2007, the Proved plus Probable NPV recycle ratio remained at 3.8 times, as in 2006. This means for each dollar invested, the Peyto team was able to create 3.8 new dollars of Proved plus Probable reserve value.
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Dec 31, Dec 31,
2007 Value Creation 2007 2006 % Change
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NPV Recycle Ratio
Proved Producing 4.7 2.9 62%
Total Proved 5.5 2.9 90%
Proved + Probable 3.8 3.8 0%
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- NPV (net present value) recycle ratio is calculated by dividing the
undiscounted NPV of reserves added in the year by the total capital
cost for the period (eg. Proved Producing ($569/$122)(equal sign)
4.7).
As is expected with the producing profile of tight gas reservoirs, the reserve life increased year over year in all of the reserve categories. The Proved plus Probable reserve life grew from 20 years at the end of 2006 to 21 years at the end of 2007. Along with this reserve life growth was a growth in the assets that fund distributions. The distribution life grew from 23 years to 24 years for the Proved Producing category, increasing the sustainability of Peyto's distributions. Also presented are other measures for comparative purposes, such as FD&A, recycle ratio and reserve replacement ratio, but it is cautioned that they are incomplete and on their own do not measure investment success.
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Proved Total Proved +
Performance Ratios Producing Proved Probable
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Reserve life index (years)
Q4 2007 average production
- 21,134 boe/d 13 16 21
Finding, development and acquisition
costs ($/boe)
2007 (Incl. change in future
development capital, "FDC") $12.68 $9.42 $9.38
2006 (Incl. change in FDC) $17.67 $19.66 $17.39
3 year average (2005-2007 incl.
change in FDC) $14.90 $14.80 $13.98
Reserve replacement ratio 1.3 1.7 1.2
Recycle ratio (Incl. change in FDC) 2.8 3.7 3.7
Distribution life (years) 24 29 40
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- FD&A (finding, development and acquisition) costs are used as a
measure of capital efficiency and are calculated by dividing the
capital costs for the period, including the change in undiscounted
future development capital ("FDC"), by the change in the reserves,
incorporating revisions and production, for the same period
(eg. Total Proved ($121,600+$2,648)/(124,328-118,681+7,544)
(equal sign)$9.42).
- The reserve life index is calculated by dividing the reserves (in
boes) in each category by the annualized average production rate in
boe/year (eg. Proved Producing 99,226/(21.134(x)365)(equal sign)13).
Peyto believes that the most accurate way to evaluate the current
reserve life is by dividing the proved developed producing reserves
by the actual fourth quarter average production. For comparative
purposes, Peyto believes the proved developed producing reserve life
provides the best measure of sustainability.
- The distribution life index is calculated by dividing the debt
adjusted undiscounted NPV (in millions$) by the Q4 annualized
distribution (in million$/year) (eg. Proved Producing
($4,694-$450.4)/($44.4(x)4) (equal sign) 24 years).
- Recycle ratio is calculated by dividing the field net back per boe,
before hedging, by the FD&A costs for the period (eg. Proved
Producing ($41.06/boe-$6.08/boe)/$12.68/boe (equal sign) 2.8). In
Peyto's opinion, it can be a very good measure of investment
performance as long as the replacement barrel is of equivalent
quality as the produced barrel. Because the recycle ratio is
comparing the netback from existing reserves to the cost of finding
new reserves it may not accurately indicate investment success.
- The reserve replacement ratio is determined by dividing the yearly
change in reserves before production by the actual annual production
for the year (eg. Total Proved ((124,291-118,681+7,544)/7,544)
(equal sign)1.7).
Quarterly Review
Daily production for the three months ending December 31, 2007 averaged 105 mmcf of natural gas and 3,675 barrels of oil and natural gas liquids. Reductions in production and commodity prices decreased funds from operations from $77.4 million in Q4 2006 to $69.0 million in Q4 2007. Peyto's commodity prices, net of hedging, decreased by 13% to average $7.67 per mcf of natural gas, and increased by 37% to average $75.23 per barrel of oil and natural gas liquids. The high heating value of Peyto's gas resulted in a 17% premium when converted from gigajoules at the AECO price hub to mcf.
Operating costs averaged $2.25/boe in the fourth quarter of 2007 compared to $2.69/boe for the fourth quarter of 2006. Operating costs have continued to fall throughout 2007 as a result of reductions in chemical consumption, electrical costs, and third party processing charges. Year after year, Peyto continues to lead the industry with its low operating costs.
Capital expenditures for the quarter totaled $35.5 million, an increase from the previous year, reflecting increased confidence in the reduced cost structure and improved returns. Consistent with past strategy, only the premium opportunities attracted Peyto's capital dollars. As usual, well-related activity made up 98% of this capital, with drilling and completion costs accounting for $29.7 million while facilities and tie-ins accounted for $5.3 million. Peyto spent $0.5 million on land and seismic in the quarter.
Activity Update
To date in 2008, Peyto has drilled 11 gross gas wells (8.9 net) and completed 7 gross zones (5.9 net). Drilling activity has been split between the winter access areas in Kakwa and the year round access areas in Sundance.
Natural gas prices have recently shown significant strength. Summer prices have risen from $6.80/GJ to over $8.00/GJ. Next winter prices have risen from $7.50/GJ to over $8.50/GJ. If realized, these prices will provide Peyto with greater funds to invest in drilling ideas. Consistent with Peyto's marketing strategy, the Trust has already forward sold 65,000 GJ for the summer at $7.01/GJ or $8.20/mcf (based on historical heat content) and 45,000 GJ for next winter at $7.72/GJ or $9.04/mcf. These forward sales provide security for distributions and capital programs while at the same time capturing prices that are the second highest ever seen for those periods.
Marketing
By design, Peyto's marketing strategy smoothes out short term fluctuations in the price of natural gas through future sales. This is done by selling approximately 30% of the natural gas, net of royalties, on the daily and monthly spot markets while the other 70% is hedged. These future sales are meant to be methodical and consistent and to avoid speculation. In general, this approach will show hedging losses when short term prices climb and hedging gains when short term prices fall. Over the long run Peyto expects to break even on forward sales. Cumulative gains since Peyto began its hedging strategy are $52 million. This hedging approach creates a forward average price typically made up of fifteen to twenty transactions placed over a 12 month period. Peyto generally sells its contracts in either the 7 month summer or the 5 month winter season.
Peyto's natural gas price before hedging averaged $6.57/mcf during the fourth quarter of 2007, a decrease of 7% from $7.08/mcf reported for the equivalent period in 2006. Oil and natural gas liquids prices averaged $76.67/bbl up 49% from $51.60/bbl a year earlier. Hedging activity for the fourth quarter of 2007 increased Peyto's achieved price by $5.19/boe. The fourth quarter hedging gain was $10.1 million, for an annual total gain of $45.8 million, as compared to the 2006 hedging gain of $37.8 million. The following table shows commodity prices and revenue before and after hedging.
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Commodity Prices Three Months ended Twelve Months ended
Dec. 31 Dec. 31
2007 2006 2007 2006
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Natural gas ($/mcf) 6.57 7.08 7.24 7.50
Hedging - gas ($/mcf) 1.10 1.76 1.18 0.96
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Natural gas - after hedging ($/mcf) 7.67 8.84 8.42 8.46
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Oil and natural gas liquids($/bbl) 76.67 51.60 66.68 62.11
Hedging - oil ($/bbl) (1.44) 3.29 1.20 (1.11)
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Oil and natural gas liquids -
after hedging ($/bbl) 75.23 54.89 67.88 61.00
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Total Hedging ($/boe) 5.19 9.30 6.08 4.53
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Revenue Three Months ended Twelve Months ended
Dec. 31 Dec. 31
($000) 2007 2006 2007 2006
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Natural gas 63,374 73,192 270,602 308,692
Oil and natural gas liquids 25,923 18,200 87,594 92,523
Hedging gain (loss) 10,090 19,304 45,837 37,793
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Total revenue 99,387 110,696 404,033 439,008
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As at December 31, 2007, Peyto had committed to the forward sale of 45,500 barrels of crude oil at an average price of $78.85 per barrel and 12.5 million gigajoules (GJ) of natural gas at an average price of $7.34 per GJ. Based on the historical heating value of Peyto's natural gas, the price per mcf of the forward sale will be $8.59, which is 2% higher than the price Peyto realized in 2007.
Performance Based Compensation
When Peyto converted to a trust in July, 2003, a performance based compensation plan was adopted. Performance based compensation was established to compensate employees for per unit market and reserve value growth. The market based component replaced the stock option plan. It was designed to be less costly, more transparent, more tax efficient for the unitholders and to provide better alignment with unitholders' objectives. The reserve value component was meant to compensate employees based on per unit growth of the Proved Producing reserve value, more conservatively discounted at 8%, independent of increases due to commodity prices. A more detailed discussion of Peyto's market and reserve value based compensation plan is available on the website.
Total performance based compensation paid in 2007 was $7.1 million (market component - $0 million; reserve value component - $7.1 million). As a testament to the effectiveness of the reserve value component, greater compensation was awarded in 2007 than in 2006, despite a 61% reduction in capital spending. This is due to the much improved efficiency and increased value creation on a per unit basis. After the performance based compensation payment, private placements are offered to Peyto employees and consultants. Unlike typical option plans, the employees of Peyto have voluntarily chosen to re-invest 96% of the after tax proceeds into Peyto Trust units at an undiscounted market price. At Peyto, there is a high degree of ownership at all levels; Board, Executive and Employee. It is through ownership that the Peyto's team is best aligned with unitholders' interests.
Sustainable Distributions
As a growth oriented, sustainable trust, Peyto's primary objective is to grow the resources from which sustainable distributions for unitholders are generated. As of December 31, 2007, cumulative distributions to unitholders totaled $622.5 million or $6.195 per unit (adjusted for 2 for 1 split). Since converting to a trust, 81% of the unit price at the time of conversion has been returned while increasing the reserves per unit by 53% and the production per unit by 23%.
Outlook
Peyto is now into its tenth year of operations with an inventory of opportunities greater than ever before. The strategy for value creation remains the same today as it did the day Peyto started. It is to generate tight gas drilling ideas that will spawn predictable and repeatable results; execute on these ideas to find and develop new reserves; operate and process the produced volumes at industry leading operating margins; optimize that operation over time to maximize value; and, ultimately, to measure investment success on the rate of return on capital deployed, and the resultant impact on per unit value creation.
Commodity prices have set the stage for an exciting year in 2008. Cost reductions have been achieved and profitability has been increased. The challenge now becomes one of increasing the scale of the business again, while keeping that profitability intact. Peyto has been successful in doing just that in the past and is confident it can be done again in the future. If one understands the value of one's own capital and is interested in understanding the value of Peyto, please visit the Peyto website at www.peyto.com where a wealth of information can be found, designed to educate and inform investors who understand value and real returns.
The current Vice-President of Exploration, Ken Veres, will be retiring effective March 31, 2008. On behalf of the directors, staff and unitholders, Peyto would like to thank Mr. Veres for his contribution over the last three years and wish him all the best in his retirement. At this time, there are no plans to replace this position as Peyto has a wealth of existing geotechnical experience to facilitate the ongoing success of our exploration strategies.
National Instrument 51-101 Cautionary Statements
The Canadian Securities Administrators have implemented standards of disclosure for reporting issuers engaged in upstream oil and gas activities effective December 31, 2003. The disclosure standards referred to as National Instrument ("NI") 51-101 establish a regime of continuous disclosure for oil and gas companies and include specific reporting requirements.
- Peyto's year-end reserve report summarized herein is compliant with
NI 51-101. Under NI 51-101's revised reserve definitions and
evaluation standards, proved plus probable reserves represent a "best
estimate" and hence for years prior to 2003, are compared to
"established" reserves which were comprised of proved plus 50 percent
of probable reserves.
- The term "boes" may be misleading particularly if used in isolation,
a boe conversion ratio of 6 mcf : 1 barrel is based on an energy
equivalency conversion method primarily applicable at the burner tip
and does not represent a value equivalency at the wellhead
- It should not be assumed that the discounted net present values
represent the fair market value of the reserves.
- Due to the effects of aggregation, the estimate of reserves and
future net revenue for individual properties may not reflect the same
confidence level as estimates of reserves and future net revenue for
all properties.
- The aggregate of the exploration and development costs incurred in
the most recent financial year, and the change during that year in
estimated future development costs, generally will not reflect total
finding and development costs related to reserve additions for that
year.
Conference Call and Webcast
A conference call will be held with the senior management of Peyto to answer questions with respect to the 2007 fourth quarter and full year financial results on Thursday, March 6th, 2008, at 9:00 a.m. Mountain Standard Time (MST), or 11:00 a.m. Eastern Standard Time (EST). To participate, please call 1-416-644-3424 (Toronto area) or 1-800-588-4942 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 21264765 followed by the pound key (No.). The replay will be available at 11:00 a.m. MST, 1:00 p.m. EST Thursday, March 6th, 2008 until midnight EST on Thursday, March 13th, 2008. The conference call can also be accessed through the internet at http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID(equal sign)2188340. After this time the conference call will be archived on the Peyto Energy Trust website at www.peyto.com.
Annual General Meeting
The Trust's Annual General Meeting of Unitholders is scheduled for 2:30 p.m. on Tuesday, May 13, 2008 at the Telus Convention Centre, Mcleod Hall B/C, 120 - 9th Avenue SE, Calgary, Alberta.
Darren Gee
President and Chief Executive Officer
March 5, 2008
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 benefitst 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.
The Toronto Stock Exchange has neither approved nor disapproved the
information contained herein.
Management's discussion and analysis
This Management's Discussion and Analysis ("MD&A") should be read in conjunction with the audited consolidated financial statements of Peyto Energy Trust ("Peyto") for the years ended December 31, 2007 and 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 March 4, 2008. Additional information about Peyto, including the most recently filed annual information form is available at www.sedar.com.
On January 1, 2008, Peyto completed an internal reorganization. As a result of this reorganization, all of the oil and gas assets of Peyto are now held in the Peyto Energy Limited Partnership. Peyto Energy Administration Corp. is the administrator of Peyto and Peyto Operating Trust, and PEDC is the general partner of the Partnership. Certain subsidiaries of Peyto were amalgamated pursuant to the internal reorganization.
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. Peyto believes that funds from operations is an important parameter to measure the value of an asset when combined with reserve life. Funds from operations is not a measure recognized by Canadian generally accepted accounting principles ("GAAP") and does not have a standardized meaning prescribed by GAAP. Therefore, funds from operations, as defined by Peyto, may not be comparable to similar measures presented by other issuers, and investors are cautioned that funds from operations should not be construed as an alternative to net earnings, cash flow from operating activities or other measures of financial performance calculated in accordance with GAAP. Funds from operations cannot be assured and future distributions may vary.
Peyto's foreign ownership level currently stands at approximately 34 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's New Royalty Framework
On October 25, 2007 the Alberta Government released a new Royalty Framework pertaining to royalties on oil and gas resources including oil sands, conventional oil and gas, and coalbed methane. This new framework was scheduled to take effect on January 1, 2009 and was based on the Alberta government's response to the recommendations put forth by the Alberta Royalty Review Panel.
On February 4, 2008, the Alberta Premier, Ed Stelmach, dissolved the provincial legislature and called for a provincial election for March 3, 2008. As the detailed legislation containing the new royalty framework was not passed, the succeeding government is now responsible for implementing any changes to the existing royalty scheme. Until that time, Peyto continues to operate under the existing Alberta royalty guidelines. Also in the interim, Alberta Energy continues to evaluate the "unintended consequences" of the proposed new framework and may provide future recommendations for modification. Should the succeeding government implement the royalty framework that was announced in October 2007, the impact to Peyto's reserves and their NPV is not expected to be material but there may be a minor negative impact on cashflow.
Federal Government's Trust Tax Legislation
On June 12, 2007, Bill C-52 (the "SIFT Rules") enacted the October 31, 2006 proposal to impose a new tax on distributions from flow-through entities, including publicly traded income trusts. Under the SIFT Rules, 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 the Federal Corporate rate and applicable provincial corporate rate. 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 tax at the trust level, distributions to tax-deferred accounts and non-residents will be reduced. On the basis of proposed legislation it is anticipated that the tax will be 26.5%. 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 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. For additional information, please refer to the February 27, 2008 press release "2007 United States Tax Information".
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, 2007, the total Proved plus Probable reserves were 164.8 million barrels of oil equivalent with a reserve life of 21 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 with the objective to deliver growth in its 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 nine years indicate that these principles have been successfully implemented. This business model makes Peyto a truly unique energy trust.
ANNUAL FINANCIAL INFORMATION
The following is a summary of selected financial information of the Trust for the periods indicated. Reference should be made to the audited consolidated financial statements of the Trust, which are available at www.sedar.com.
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Year Ended December 31 2007 2006 2005
($000 except per unit amounts)
-------------------------------------------------------------------------
Total revenue (before royalties) 404,033 439,008 431,695
Funds from operations 279,624 305,845 296,970
Per unit - basic 2.65 2.93 3.01
Per unit - diluted 2.65 2.93 3.01
Earnings 208,884 195,228 161,568
Per unit - basic 1.98 1.86 1.64
Per unit - diluted 1.98 1.86 1.64
Total assets 1,192,232 1,136,700 944,927
Total long-term debt 430,000 420,000 180,000
Cash distributions per unit 1.68 1.66 1.39
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QUARTERLY FINANCIAL INFORMATION
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2007
($000 except per unit amounts) Q4 Q3 Q2 Q1
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Total revenue (net of royalties) 82,307 75,589 83,017 92,499
Funds from operations 68,976 62,938 69,345 78,364
Per unit - basic 0.65 0.60 0.66 0.74
Per unit - diluted 0.65 0.60 0.66 0.74
Earnings 73,289 39,886 38,825 56,883
Per unit - basic 0.69 0.37 0.37 0.54
Per unit - diluted 0.69 0.37 0.37 0.54
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2006
($000 except per unit amounts) Q4 Q3 Q2 Q1
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Total revenue (net of royalties) 91,425 84,164 88,515 86,459
Funds from operations 77,360 72,360 77,507 78,617
Per unit - basic 0.74 0.69 0.74 0.76
Per unit - diluted 0.74 0.69 0.74 0.76
Earnings 47,012 46,155 56,768 45,293
Per unit - basic 0.44 0.44 0.54 0.44
Per unit - diluted 0.44 0.44 0.54 0.44
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RESULTS OF OPERATIONS
Production
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Three Months ended Twelve Months ended
Dec. 31 Dec. 31
2007 2006 2007 2006
-------------------------------------------------------------------------
Natural gas (mmcf/d) 104,749 112,296 102,418 112,751
Oil & natural gas liquids (bbl/d) 3,675 3,834 3,599 4,081
Barrels of oil equivalent (boe/d) 21,134 22,550 20,669 22,873
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Natural gas production averaged 104.7 mmcf/d in the fourth quarter of 2007, 7 percent lower than the 112.3 mmcf/d reported for the same period in 2006. Oil and natural gas liquids production averaged 3,675 bbl/d, a decrease of 4 percent from 3,834 bbl/d reported in the prior year. Production for the year decreased 10 percent from 22,873 boe/d to 20,669 boe/d. The production decreases are attributable to Peyto's reduced drilling program and natural production declines.
Commodity Prices
-------------------------------------------------------------------------
Three Months ended Twelve Months ended
Dec. 31 Dec. 31
2007 2006 2007 2006
-------------------------------------------------------------------------
Natural gas ($/mcf) 6.57 7.08 7.24 7.50
Hedging - gas ($/mcf) 1.10 1.76 1.18 0.96
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Natural gas - after hedging ($/mcf) 7.67 8.84 8.42 8.46
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Oil and natural gas liquids($/bbl) 76.67 51.60 66.68 62.11
Hedging - oil ($/bbl) (1.44) 3.29 1.20 (1.11)
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Oil and natural gas liquids -
after hedging ($/bbl) 75.23 54.89 67.88 61.00
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Total Hedging ($/boe) 5.19 9.30 6.08 4.53
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Peyto's natural gas price before hedging averaged $6.57/mcf during the
fourth quarter of 2007, a decrease of 7 percent from $7.08/mcf reported for
the equivalent period in 2006. Oil and natural gas liquids prices averaged
$76.67/bbl up 49 percent from $51.60/bbl a year earlier. Average natural gas
prices for the year were down 3 percent at $7.24/mcf while oil and natural gas
liquids prices were up 7 percent at $66.68/bbl compared to 2006. Hedging
activity for fiscal 2007 increased Peyto's price achieved by $6.08/boe.
Revenue
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Three Months ended Twelve Months ended
Dec. 31 Dec. 31
($000) 2007 2006 2007 2006
-------------------------------------------------------------------------
Natural gas 63,374 73,192 270,602 308,692
Oil and natural gas liquids 25,923 18,200 87,594 92,523
Hedging gain (loss) 10,090 19,304 45,837 37,793
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Total revenue 99,387 110,696 404,033 439,008
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For the three months ended December 31, 2007, gross revenue decreased
10 percent to $99.4 million from $110.7 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:
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Three Months ended Twelve Months ended
Dec. 31 Dec. 31
2007 2006 $million 2007 2006 $million
-------------------------------------------------------------------------
Total Revenue,
Dec 31, 2006 110.7 439.0
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Revenue change due to:
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Natural gas
Volume (mmcf) 9637 10,331 (6.1) 37,382 41,154 (31.9)
Price ($/mcf) 7.67 $8.84 (11.3) 8.42 $8.46 (1.5)
Oil & NGL
Volume (mbbl) 338 353 (0.8) 982.5 1,490 (10.7)
Price ($/bbl) 75.23 $54.89 6.9 67.88 $61.00 9.0
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Total Revenue,
Dec 31, 2007 99.4 404.0
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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.
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Three Months ended Twelve Months ended
Dec. 31 Dec. 31
2007 2006 2007 2006
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Royalties, net of ARTC ($000) 17,080 19,271 70,621 88,446
% of sales 17 18 18 21
$/boe 8.78 9.29 9.36 10.59
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For the fourth quarter of 2007, royalties averaged $8.78/boe or approximately 17 percent of Peyto's total petroleum and natural gas sales. Royalties for the year were 18 percent of sales in 2007 compared to 21 percent in 2006. 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 the crown royalty rate. Effective January 1, 2007, the Alberta Government discontinued the Alberta Royalty Tax Credit ("ARTC") program.
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 Twelve Months ended
Dec. 31 Dec. 31
2007 2006 2007 2006
-------------------------------------------------------------------------
Operating costs ($000)
Field expenses 7,136 7,361 28,433 25,765
Processing and gathering income (2,753) (1,780) (9,074) (7,719)
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Total operating costs 4,383 5,581 19,359 18,046
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$/boe 2.25 2.69 2.57 2.16
-------------------------------------------------------------------------
Transportation 1,052 1,089 4,296 4,856
-------------------------------------------------------------------------
$/boe 0.54 0.52 0.57 0.58
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Operating costs were $4.4 million in the fourth quarter of 2007 compared to $5.6 million during the same period a year earlier. On a unit of production basis, operating costs averaged $2.25/boe in the fourth quarter of 2007 compared to $2.69/boe for the fourth quarter of 2006. Operating costs for the year averaged $2.57/boe in 2007 compared to $2.16/boe in 2006. Operating costs were down over the course of the year as a result of reductions in chemical consumption, electrical costs, and third party processing charges. At the beginning of October, production from the Chime area was rerouted from costly third party processing to Peyto's wholly owned Kakwa facility. Transportation expense remained constant.
Netbacks
Operating netbacks represent the profit margin associated with the production and sale of petroleum and natural gas. The primary factors that produce Peyto's strong netbacks are a low cost structure and the high heat content of its natural gas that results in higher commodity prices.
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Three Months ended Twelve Months ended
Dec. 31 Dec. 31
($/boe) 2007 2006 2007 2006
-------------------------------------------------------------------------
Sale Price 51.12 53.35 53.56 52.58
Less:
Royalties 8.78 9.29 9.36 10.59
Operating costs 2.25 2.69 2.57 2.16
Transportation 0.54 0.52 0.57 0.58
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Operating netback 39.55 40.85 41.06 39.25
General and administrative 0.87 0.85 0.94 0.48
Interest on long-term debt 3.19 2.72 3.05 2.16
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Cash netback 35.49 37.28 37.07 36.61
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General and Administrative Expenses
-------------------------------------------------------------------------
Three Months ended Twelve Months ended
Dec. 31 Dec. 31
2007 2006 2007 2006
-------------------------------------------------------------------------
G&A expenses ($000) 2,648 2,426 10,242 9,397
Overhead recoveries (950) (669) (3,117) (5,431)
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Net G&A expenses 1,698 1,757 7,125 3,966
-------------------------------------------------------------------------
$/boe 0.87 0.85 0.94 0.48
-------------------------------------------------------------------------
General and administrative expenses before overhead recoveries remained relatively constant in the fourth quarter of 2007, as compared to the same period in 2006. Net of overhead recoveries associated with the capital expenditures program, general and administrative costs increased to $0.87 per boe in the fourth quarter of 2007, from $0.85 per boe in the fourth quarter of 2006. Fourth quarter 2007 capital overhead recoveries were 42% higher than fourth quarter 2006 recoveries but were down 43% on an annual basis. General and administrative expenses for 2007 averaged $0.94/boe in 2007 compared to $0.48 in 2006.
Interest Expense
-------------------------------------------------------------------------
Three Months ended Twelve Months ended
Dec. 31 Dec. 31
2007 2006 2007 2006
-------------------------------------------------------------------------
Interest expense ($000) 6,198 5,638 23,007 18,011
$/boe 3.19 2.72 3.05 2.16
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2007 interest expense was $23.0 million or $3.05/boe compared to $18.0 million or $2.16/boe a year earlier. Average bank debt for 2007 was $405 million as compared to $360 million for 2006. Interest rates continue to be favorable and are not expected to increase substantially in the short term.
Depletion, Depreciation and Accretion
The 2007 provision for depletion, depreciation and accretion totaled $75.8 million as compared to $81.2 million in 2006. On a unit of production basis, depletion, depreciation and accretion costs averaged $10.05/boe as compared to $9.71/boe in 2006. Increases or decreases in the depletion rate on a unit of production basis are influenced by the reserves added through Peyto's drilling program.
Income Taxes
The current provision for recovery of future income tax was $12.5 million in 2007 down from an expense of $27.4 million in 2006. Included in the 2007 provision was a recovery of $31.0 million recorded in the fourth quarter (2006 expense - $8.0 million). This reduction of future income tax liability is due to the reduction in tax rates for future years at the trust level. 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. The capital program generates resource pools which are available to offset current and future income tax liabilities. Unitholders benefit as the use of these resource pools increases the tax free return of capital component of the cash distributions. At December 31, 2007 the Trust has tax pools of approximately $660.1 million (December 31, 2006 - $670.8 million) available for deduction against future income.
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 2007, a hedging gain of $45.8 million was recorded as compared to a hedging gain of $37.8 million in 2006. A summary of contracts outstanding in respect of the hedging activities are as follows:
Crude Oil Price Period Hedged Type Daily Volume (CAD) ------------------------------------------------------------------------- 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 Natural Gas Price Period Hedged Type Daily Volume (CAD) ------------------------------------------------------------------------- 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 to October 31, 2008 Fixed price 5,000 GJ $6.60/GJ April 1 to October 31, 2008 Fixed price 5,000 GJ $6.80/GJ April 1 to October 31, 2008 Fixed price 5,000 GJ $7.05/GJ April 1 to October 31, 2008 Fixed price 5,000 GJ $7.20/GJ April 1 to October 31, 2008 Fixed price 5,000 GJ $7.10/GJ April 1 to October 31, 2008 Fixed price 5,000 GJ $7.20/GJ April 1 to October 31, 2008 Fixed price 5,000 GJ $7.40/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 Nov 1, 2008 to March 31, 2009 Fixed price 5,000 GJ $7.60/GJ Nov 1, 2008 to March 31, 2009 Fixed price 5,000 GJ $8.00/GJ Nov 1, 2008 to March 31, 2009 Fixed price 5,000 GJ $8.25/GJ Nov 1, 2008 to March 31, 2009 Fixed price 5,000 GJ $8.40/GJ Nov 1, 2008 to March 31, 2009 Fixed price 5,000 GJ $8.65/GJ
As at December 31, 2007, the Trust had committed to the future sale of 45,500 barrels of crude oil at an average price of $78.85 per barrel and 12,465,000 gigajoules (GJ) of natural gas at an average price of $7.34 per GJ or $8.59 per mcf based on the historical heating value of Peyto's natural gas. Had these contracts been closed on December 31, 2007, the Trust would have realized a gain in the amount of $7.4 million.
Commodity Price Sensitivity
Low operating costs, low distribution ratio and long reserve life reduce Peyto's sensitivity to long-term changes in commodity prices.
Currency Risk Management
The Trust is exposed to fluctuations in the Canadian/US dollar exchange ratio since 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 in Canadian currency. 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 there are no agreements to manage this risk. At December 31, 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 $4.1 million per annum.
LIQUIDITY AND CAPITAL RESOURCES
Funds from Operations
-------------------------------------------------------------------------
Three Months ended Twelve Months ended
Dec. 31 Dec. 31
($000 except per unit amounts) 2007 2006 2007 2006
-------------------------------------------------------------------------
Net earnings 73,289 47,012 208,884 195,228
Items not requiring cash:
Provision for (recovery of)
performance based compensation (371) (10,340) 269 (10,149)
Future income tax expense (30,226) 7,980 (12,453) 27,357
Depletion, depreciation &
accretion 19,151 20,397 75,791 81,098
Non-recurring items:
Market and reserve value
performance based compensation 7,133 12,311 7,133 12,311
-------------------------------------------------------------------------
Funds from operations 68,976 77,360 279,624 305,845
-------------------------------------------------------------------------
Funds from operations per unit 0.65 0.74 2.65 2.93
-------------------------------------------------------------------------
For the quarter ended December 31, 2007, funds from operations totaled $69.0 million or $0.65 per unit, as compared to $77.3 million, or $0.74 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. 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 2007 was 5.7% (2006 - 5.0%).
At December 31, 2007, $430 million was drawn under the facility. Working capital liquidity is maintained by drawing from and repaying the unutilized credit facility as needed. At December 31, 2007, the working capital deficit was $22.3 million.
Peyto believes that funds generated from operations, together with borrowings under the credit facility and proceeds from equity issued will be sufficient to finance current operations and the planned capital expenditure program. The total amount of capital invested in 2008 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 low risk development gas wells. Peyto 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 December 31, 2007, 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) Amount
($000) Number of 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, December 31, 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%.
-------------------------------------------------------------------------
($millions except unit values) 2007 2006 Change
-------------------------------------------------------------------------
Net present value of proved producing
reserves at 8% based on constant
Paddock Lindstrom 2008 price forecast 1,725.0 1,708.0
Net debt before performance
based compensation (450.3) (433.6)
2007 distributions - (177.5)
---------------------------------
Net value 1,274.7 1,096.9 177.8
Equity adjustment factor(x) 100%
-----------
Equity adjusted increase in value 177.8
-----------
2007 reserve value based compensation
at 4% 7.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(x) Equity adjustment factor is calculated as the percent increase in
value per unit divided by the total percent increase in value
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 2008, a tax factor of 1.333 will then be applied to determine the amount to be paid. Commencing for rights vesting in 2009, no tax factor will be applied to determine the amount paid. The 2007 market based component was based on 1.2 million vested rights at an average grant price of $24.16, average cumulative distributions of $4.73 and the five day weighted average closing price of $16.48.
The total amount expensed under these plans was as follows:
-------------------------------------------------------------------------
2007 2006
($000) $ $
-------------------------------------------------------------------------
Market based compensation 13 8,491
Reserve value based compensation 7,120 4,570
Recovery of prior year unpaid reserve bonus - (750)
-------------------------------------------------------------------------
Total 7,133 12,311
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liability for future market based compensation as at December 31, 2007 related to $3.0 million non-vested rights with an average grant price of $21.04 were $269,000 (2006 - nil).
Capital Expenditures
Net capital expenditures for the fourth quarter of 2007 totaled $35.5 million. Exploration and development related activity represented $29.7 million or 84% of the total, while expenditures on facilities, gathering systems and equipment totaled $5.3 million or 15% of the total. The following table summarizes capital expenditures for the year.
-------------------------------------------------------------------------
Three Months ended Twelve Months ended
Dec. 31 Dec. 31
($000) 2007 2006 2007 2006
-------------------------------------------------------------------------
Land - - 984 13,253
Seismic 464 583 1,799 8,944
Drilling - Exploratory &
Development 29,734 22,777 96,908 227,585
Production Equipment, Facilities
& Pipelines 5,326 5,036 21,834 61,961
Acquisitions & Dispositions - - - -
Office Equipment 22 17 46 183
-------------------------------------------------------------------------
Total Capital Expenditures 35,546 28,413 121,571 311,926
-------------------------------------------------------------------------
Cash Distributions
-------------------------------------------------------------------------
Three Months ended Twelve Months ended
Dec. 31 Dec. 31
2007 2006 2007 2006
-------------------------------------------------------------------------
Funds from operations ($000) 68,976 77,360 279,624 305,845
Total distributions ($000) 44,399 44,206 177,548 173,755
Total distributions per unit ($) 0.42 0.42 1.68 1.66
Payout ratio (%) 64 57 63 57
Cash distributions ($000)
(net of DRIP) 44,399 44,206 177,548 158,204
Payout ratio (%) 64 57 63 52
-------------------------------------------------------------------------
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 Twelve Months ended
Dec. 31 Dec. 31
($000) 2007 2006 2007 2006
-------------------------------------------------------------------------
Opening accumulated earnings 666,749 484,142 531,154 335,926
Net earnings for the period 73,289 47,012 208,884 195,228
-------------------------------------------------------------------------
Total accumulated earnings 740,038 531,154 740,038 531,154
Total accumulated distributions (622,466) (400,712) (622,466) (444,918)
-------------------------------------------------------------------------
Accumulated earnings per
Balance Sheet 117,572 83,430 117,572 86,236
-------------------------------------------------------------------------
Since inception, Peyto has accumulated earnings of $740.0 million and
distributed $622.5 million to unitholders.
Contractual Obligations
The Trust is committed to payments under operating leases for office space
as follows:
-------------------------------------------------------------------------
($000) $
-------------------------------------------------------------------------
2008 1,097
2009 1,097
2010 1,097
2011 1,097
-------------------------------------------------------------------------
4,388
-------------------------------------------------------------------------
-------------------------------------------------------------------------
GUARANTEES/OFF BALANCE SHEET ARRANGEMENTS
The Trust is a party to certain off balance sheet derivative financial instruments, including fixed price contracts as discussed further in the Hedging section.
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. For the year ended December 31, 2007, legal fees totaled $1.1 million.
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.
For 2007, the Trust paid distributions to the unitholders in the amount of $177.5 million (2006 - $173.8 million) in accordance with the following schedule:
Production Period Record Date Distribution Date Per Unit(x)
-------------------------------------------------------------------------
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 14, 2007 $0.14
July 2007 July 31, 2007 August 15, 2007 $0.14
August 2007 August 31, 2007 September 15, 2007 $0.14
September 2007 September 30, 2007 October 13, 2007 $0.14
October 2007 October 31, 2007 November 15, 2007 $0.14
November 2007 November 30, 2007 December 15, 2007 $0.14
December 2007 December 31, 2007 January 15, 2008 $0.14
-------
$1.68
-------
-------
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 depends 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 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 an 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 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 utilize appropriate technology in 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 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 are able to respond to changes as they occur.
The petroleum and natural gas industry is subject to both environmental regulations and an increased environmental awareness. Peyto has reviewed its environmental risks and is, to the best of its knowledge, in compliance with the appropriate environmental legislation and have determined that there is no current material impact on 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, if appropriate, 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 Chief Financial Officer ("CFO"), 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 continues to evaluate 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 CFO. Based on this evaluation, the CEO and CFO 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 OVER FINANCIAL REPORTING
Internal controls have been designed to provide reasonable assurance regarding the reliability of the Trust's financial reporting and the preparation of financial statements together with the other financial information for external purposes in accordance with the Canadian GAAP. The Trust's Chief Executive Officer and Chief Financial Officer have designed or caused to be designed under their supervision internal controls over financial reporting related to the Trust, including its consolidated subsidiaries.
The Trust's Chief Executive Officer and Chief Financial Officer are required to cause the Trust to disclose herein any change in the Trust's internal control over financial reporting that occurred during the Trust's most recent interim period that materially affected, or is reasonably likely to materially affect the Trust's internal control over financial reporting. No material changes were identified in the Trust's internal control of financial reporting during the year ended December 31, 2007, that had materially affected, or are reasonably likely to materially affect, the Trust's internal control of financial reporting.
It should be noted that a control system, including the Trust's disclosure and internal controls and procedures, no matter how well conceived, can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud.
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, 2007 were audited by independent petroleum engineers Paddock Lindstrom & Associates Ltd. Paddock has been evaluating reserves in this area and for Peyto for 9 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 year end independent reserves evaluation which was completed in January 2008. 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.
RECENT ACCOUNTING PRONOUNCEMENTS
As of January 1, 2008, the Trust adopted 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 additional disclosures required.
As of January 1, 2008, the Trust adopted 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 additional disclosures required.
As of January 1, 2009, the Trust will be required to adopt new CICA Handbook Section 3064 "Goodwill and Intangible Assets" which replaces Section 3062 "Goodwill and Other Intangible Assets" and Section 3450 "Research and Development Costs." Various changes have been made to other standards to be consistent with the new Section 3064, which establishes standards for the recognition, measurement, presentation and disclosure of goodwill and of intangible assets. Standards concerning goodwill are unchanged from the standards in the previous Section 3062. The Trust is assessing the impact of this new standard on its consolidated financial statements, however, the adoption is not expected to have a material impact on its consolidated financial statements.
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
Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Operations
Production
Natural gas (mcf/d) 104,749 97,000 101,812 106,183
Oil & NGLs (bbl/d) 3,675 3,573 3,540 3,607
Barrels of oil
equivalent (boe/d @
6:1) 21,134 19,740 20,509 21,305
Average product prices
Natural gas ($/mcf) 7.67 7.61 8.59 9.77
Oil & natural gas
liquids ($/bbl) 75.23 70.51 65.65 59.79
Average operating
expenses ($/boe) 2.25 2.48 2.70 2.84
Average transportation
costs ($/boe) 0.54 0.58 0.57 0.59
Field netback ($/boe) 39.54 38.57 41.21 44.82
General & administrative
expense ($/boe) 0.87 0.82 1.10 0.98
Interest expense ($/boe) 3.19 3.10 2.95 2.96
Financial
($000 except per unit)
Revenue 99,387 91,070 100,750 112,825
Royalties (net of ARTC) 17,080 15,482 17,734 20,326
Funds from operations 68,976 62,938 69,345 78,364
Funds from operations
per unit 0.65 0.60 0.66 0.74
Total distributions 44,399 44,399 44,399 44,350
Total distributions
per unit 0.42 0.42 0.42 0.42
Payout ratio 64% 71% 64% 57%
Cash distributions
(net of DRIP) 44,399 44,399 44,399 44,350
Payout ratio 64% 71% 64% 57%
Earnings 73,289 39,886 38,825 56,883
Earnings per
diluted unit 0.69 0.37 0.37 0.54
Capital expenditures 35,546 42,598 12,949 30,478
Weighted average
trust units
outstanding 105,712,364 105,712,364 105,712,364 105,542,484
-----------------------------------------------
2006
Q4 Q3
-----------------------------------------------
Operations
Production
Natural gas (mcf/d) 112,296 115,304
Oil & NGLs (bbl/d) 3,834 4,205
Barrels of oil
equivalent
(boe/d at 6:1) 22,550 23,422
Average product prices
Natural gas ($/mcf) 8.84 7.81
Oil & natural gas
liquids ($/bbl) 54.89 64.50
Average operating
expenses ($/boe) 2.69 1.90
Average transportation
costs ($/boe) 0.52 0.58
Field netback ($/boe) 40.85 36.58
General & administrative
expense ($/boe) 0.85 0.55
Interest expense ($/boe) 2.72 2.52
Financial
($000 except per unit)
Revenue 110,696 107,844
Royalties (net of ARTC) 19,271 23,680
Funds from operations 77,360 72,360
Funds from operations
per unit 0.74 0.69
Total distributions 44,206 44,111
Total distributions
per unit 0.42 0.42
Payout ratio 57% 61%
Cash distributions
(net of DRIP) 44,206 41,019
Payout ratio 57% 57%
Earnings 47,012 46,155
Earnings per
diluted unit 0.44 0.44
Capital expenditures 28,413 71,223
Weighted average
trust units
outstanding 105,251,394 104,924,702
Peyto Energy Trust
Consolidated Balance Sheets
($000)
December 31, December 31,
2007 2006
-------------------------------------------------------------------------
Assets
Current
Cash 20,547 10,806
Accounts receivable 47,728 53,418
Due from private placements (Note 7) - 5,042
Financial derivative assets (Notes 3 and 13) 7,405 -
Prepaid expenses and deposits 5,020 2,681
-------------------------------------------------------------------------
80,700 71,947
Property, plant and equipment (Note 4) 1,111,532 1,064,753
-------------------------------------------------------------------------
1,192,232 1,136,700
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities and Unitholders' Equity
Current
Accounts payable and accrued liabilities 85,923 70,836
Cash distributions payable 14,800 14,735
Provision for future performance based
compensation 16 -
Future income taxes (Note 12) 2,285 -
-------------------------------------------------------------------------
103,024 85,571
-------------------------------------------------------------------------
Long-term debt (Note 5) 430,000 420,000
Provision for future performance based
compensation 253 -
Asset retirement obligations (Note 6) 6,766 5,767
Future income taxes (Note 12) 123,197 135,650
-------------------------------------------------------------------------
560,216 561,417
-------------------------------------------------------------------------
Unitholders' equity
Unitholders' capital (Note 7) 406,301 398,434
Units to be issued (Note 7) - 5,042
Accumulated earnings (Note 8) 117,572 86,236
Accumulated other comprehensive income 5,119 -
-------------------------------------------------------------------------
528,992 489,712
-------------------------------------------------------------------------
1,192,232 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)
For the years ended December 31,
2007 2006
-------------------------------------------------------------------------
Revenue
Petroleum and natural gas sales, net 333,411 350,562
-------------------------------------------------------------------------
Expenses
Operating (Note 9) 19,359 18,046
Transportation 4,296 4,856
General and administrative (Note 10) 7,125 3,966
Performance based compensation (Note 11) 7,133 12,311
Future performance based compensation 269 (10,149)
Interest on long term debt 23,007 18,011
Depletion, depreciation and accretion
(Notes 4 and 6) 75,791 81,098
-------------------------------------------------------------------------
136,980 128,139
-------------------------------------------------------------------------
Earnings before taxes 196,431 222,423
-------------------------------------------------------------------------
Taxes
Future income tax expense (Note 12) (12,453) 27,357
Capital tax expense - (162)
-------------------------------------------------------------------------
(12,453) 27,195
-------------------------------------------------------------------------
Net earnings for the year 208,884 195,228
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per unit (Note 7)
Basic 1.98 1.86
Diluted 1.98 1.86
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
Peyto Energy Trust
Consolidated Statements of Comprehensive Income
($000)
For the years ended December 31,
2007 2006
-------------------------------------------------------------------------
Net earnings for the year 208,884 195,228
Other comprehensive income (loss)
Change in unrealized gain on cash flow
hedges, net of tax of $2,178 4,880 -
Realized (gain) loss on cash flow hedges,
net of tax $10,356 (23,202) -
-------------------------------------------------------------------------
Comprehensive Income (Note 3) 190,562 195,228
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
Peyto Energy Trust
Consolidated Statements of Accumulated Earnings and Accumulated Other
Comprehensive Income
($000)
For the years ended December 31,
2007 2006
-------------------------------------------------------------------------
Accumulated earnings, beginning of year 86,236 64,763
Net earnings for the year 208,884 195,228
Distributions (Note 8) (177,548) (173,755)
-------------------------------------------------------------------------
Accumulated earnings, end of year 117,572 86,236
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Accumulated other comprehensive income,
beginning of year - -
Adoption of financial instruments, net of
tax of $10,463 (Notes 3 and 13) 23,441 -
Other comprehensive income (Notes 3 and 13) (18,322) -
-------------------------------------------------------------------------
Accumulated other comprehensive income,
end of year 5,119 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
Peyto Energy Trust
Consolidated Statements of Cash Flows
($000)
For the years ended December 31,
2007 2006
$ $
-------------------------------------------------------------------------
Cash provided by (used in)
Operating Activities
Net earnings for the year 208,884 195,228
Items not requiring cash:
Future performance based compensation 269 (10,149)
Future income tax expense (12,453) 27,357
Depletion, depreciation and accretion 75,791 81,098
Change in non-cash working capital related
to operating activities (Note 14) 16,215 (37,489)
-------------------------------------------------------------------------
288,706 256,045
-------------------------------------------------------------------------
Financing Activities
Issue of trust units, net of costs 2,825 30,857
Cash distributions paid (net of DRIP) (177,548) (158,204)
Increase in bank debt 10,000 240,000
Change in non-cash working capital related
to financing activities (Note 14) 5,107 25,613
-------------------------------------------------------------------------
(159,616) 138,266
-------------------------------------------------------------------------
Investing Activities
Additions to property, plant and equipment (121,571) (311,926)
Change in non-cash working capital related
to investing activities (Note 14) 2,222 (71,579)
-------------------------------------------------------------------------
(119,349) (383,505)
-------------------------------------------------------------------------
Net increase (decrease) in cash 9,741 10,806
Cash, beginning of year 10,806 -
-------------------------------------------------------------------------
Cash, end of year 20,547 10,806
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
Peyto Energy Trust
Notes to Consolidated Financial Statements
December 31, 2007 and 2006
1. Nature of Operations
Peyto Energy Trust (the "Trust") is an unincorporated open-ended
limited purpose trust established under the laws of the Province of
Alberta. The Trust indirectly owns all of the securities of Peyto
Exploration & Development Corp. ("Peyto") which entitles the Trust to
receive all cash flow available for distribution from the business of
Peyto after debt service payments, maintenance capital expenditures
and other cash requirements. The unitholders of the Trust are
entitled to receive cash distributions paid by the Trust and are
entitled to one vote for each Trust unit held at unitholder meetings.
The Trust units trade on the TSX under the symbol "PEY.UN". The
Trust's principal business activity is the exploration for and
development and production of petroleum and natural gas in western
Canada.
2. Summary of Significant Accounting Policies
These consolidated financial statements have been prepared by
management in accordance with Canadian generally accepted accounting
principles. Because a precise determination of many assets and
liabilities is dependent upon future events, the preparation of
periodic financial statements necessarily involves the use of
estimates and approximations. Accordingly, actual results could
differ from those estimates. The financial statements have, in
management's opinion, been properly prepared within reasonable limits
of materiality and within the framework of the Trust's accounting
policies summarized below.
These financial statements include the accounts of the Trust and its
wholly owned subsidiaries, Peyto and Peyto Operating Trust ("POT").
Joint operations
The Trust conducts a portion of its petroleum and natural gas
exploration, development and production activities jointly with
others and, accordingly, these consolidated financial statements
reflect only the Trust's proportionate interest in such activities.
Property, plant and equipment
The Trust follows the full cost method of accounting for its
petroleum and natural gas properties. All costs related to the
acquisition, exploration and development of petroleum and natural gas
reserves are capitalized. Such costs include lease acquisition costs,
geological and geophysical costs, carrying charges of non-producing
properties, costs of drilling both productive and non-productive
wells, the cost of petroleum and natural gas production equipment and
overhead charges related to exploration and development activities.
All other general and administrative costs are expensed as incurred.
The Trust evaluates its petroleum and natural gas assets to determine
that the costs are recoverable and do not exceed the fair value of
the properties ("ceiling test"). The costs are assessed to be
recoverable if the sum of the undiscounted cash flows expected from
the production of proved reserves plus the cost of unproved
properties, less impairment, exceed the carrying value of the oil and
gas assets. If the carrying value of the petroleum and natural gas
properties is not determined to be recoverable, an impairment loss is
recognized to the extent that the carrying value exceeds the sum of
the discounted cash flows expected from the production of proved and
probable reserves plus the cost of unproved properties. The cash
flows are estimated using the future product prices and costs and are
discounted using a risk-free rate.
Proceeds from the disposition of petroleum and natural gas properties
are applied against capitalized costs except for dispositions that
would change the rate of depletion and depreciation by 20% or more,
in which case a gain or loss would be recorded.
All costs of acquisition, exploration and development of petroleum
and natural gas reserves (net of salvage value) and estimated costs
of future development of proved undeveloped reserves are depleted and
depreciated using the unit of production method based on estimated
gross proved reserves as determined by independent engineers. For
purposes of the depletion and depreciation calculation, relative
volumes of petroleum and natural gas production and reserves are
converted at the energy equivalent conversion rate of six thousand
cubic feet of natural gas to one barrel of crude oil.
Costs of unproved properties are initially excluded from petroleum
and natural gas properties for the purpose of calculating depletion.
When proved reserves are assigned to the property or it is considered
to be impaired, the cost of the property or the amount of the
impairment is added to costs subject to depletion. Depreciation of
gas plants and related facilities is calculated on a straight-line
basis over a 20-year term. Office furniture and equipment are
depreciated over their estimated useful lives at declining balance
rates between 20% and 30%.
Asset retirement obligations
The Trust records a liability for the fair value of legal obligations
associated with the retirement of long-lived tangible assets in
the period in which they are incurred, normally when the asset is
purchased or developed. On recognition of the liability there is a
corresponding increase in the carrying amount of the related asset
known as the asset retirement cost, which is depleted on a unit-of-
production basis over the life of the reserves. The liability is
adjusted each reporting period to reflect the passage of time, with
the accretion charged to earnings, and for revisions to the estimated
future cash flows. Actual costs incurred upon settlement of the
obligations are charged against the liability.
Hedging
The Trust uses derivative financial instruments from time to time to
hedge its exposure to commodity price fluctuations. The Trust does
not enter into derivative financial instruments for trading or
speculative purposes. All derivative financial instruments are
initiated within the guidelines of the Trust's risk management
policy. This includes linking all derivatives to specific assets and
liabilities on the balance sheet or to specific firm commitments or
forecasted transactions. The Trust enters into hedges of its exposure
to petroleum and natural gas commodity prices by entering into crude
oil and natural gas swap contracts, options or collars, when it is
deemed appropriate. These derivative contracts, accounted for as
hedges, are recognized on the balance sheet. Realized gains and
losses on these contracts are recognized in petroleum and natural gas
revenue and cash flows in the same period in which the revenues
associated with the hedged transaction are recognized. Premiums paid
or received are deferred and amortized to earnings over the term of
the contract. For financial derivative contracts settling in future
periods, a financial asset or liability is recognized in the balance
sheet and measured at fair value, with changes in fair value
recognized in other comprehensive income.
Revenue recognition
Petroleum and natural gas sales are recognized as revenue when title
passes to purchasers, normally at pipeline delivery point for natural
gas and at the wellhead for crude oil.
Measurement uncertainty
The amounts recorded for depletion and depreciation of property,
plant and equipment, the asset retirement obligation and the ceiling
test calculation are based on estimates of gross proved reserves,
production rates, petroleum and natural gas prices, future costs and
other relevant assumptions. By their nature, these estimates are
subject to measurement uncertainty and the effect on the financial
statements of changes in such estimates in future years could be
significant.
Future income taxes
The Trust follows the liability method of tax allocation. Under this
method future income tax assets and liabilities of its subsidiaries
are determined based on differences between financial reporting and
income tax bases of assets and liabilities, and are measured using
substantively enacted tax rates and laws that will be in effect when
the differences are expected to reverse.
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.
3. 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 retrospectively without restatement. 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. As at January 1, 2007, the Trust has made the following
classifications:
---------------------------------------------------------------------
Financial Assets & Liabilities Category
---------------------------------------------------------------------
Cash Held for trading
---------------------------------------------------------------------
Accounts Receivable Loans & receivables
---------------------------------------------------------------------
Due from Private Placement Loans & receivables
---------------------------------------------------------------------
Accounts Payable & Accrued Liabilities Other Liabilities
---------------------------------------------------------------------
Provision for Future Performance Based
Compensation Other Liabilities
---------------------------------------------------------------------
Cash Distributions Payable Other Liabilities
---------------------------------------------------------------------
Long Term Debt Other Liabilities
---------------------------------------------------------------------
Risk Management Contracts Held for trading
---------------------------------------------------------------------
b) Derivative Instruments and Hedging Activities
Derivative instruments are utilized by the Trust to manage market
risk against 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 to be treated as a
financial derivative. 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 Handbook 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 of the period of change. 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 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 additional disclosures
required.
As of January 1, 2009, the Trust will be required to adopt new CICA
Handbook Section 3064 "Goodwill and Intangible Assets" which replaces
Section 3062 "Goodwill and Other Intangible Assets" and Section 3450
"Research and Development Costs." Various changes have been made to
other standards to be consistent with the new Section 3064, which
establishes standards for the recognition, measurement, presentation
and disclosure of goodwill and of intangible assets. Standards
concerning goodwill are unchanged from the standards in the previous
Section 3062. The Trust is assessing the impact of this new standard
on its consolidated financial statements, however, the adoption is
not expected to have a material impact on its consolidated financial
statements.
4. Property, Plant and Equipment
($000) 2007 2006
---------------------------------------------------------------------
Property, plant and equipment 1,410,767 1,288,616
Accumulated depletion and depreciation (299,235) (223,863)
---------------------------------------------------------------------
1,111,532 1,064,753
---------------------------------------------------------------------
---------------------------------------------------------------------
At December 31, 2007 costs of $37,825,472 (December 31, 2006 -
$38,939,577) related to undeveloped land have been excluded from the
depletion and depreciation calculation.
The Trust performed a ceiling test calculation at December 31, 2007
resulting in the undiscounted cash flows from proved reserves plus
the cost of unproved properties, less impairment, exceeding the
carrying value of petroleum and natural gas assets. The impairment
test was calculated at December 31, 2007 using the following
independent engineering consultant's forecasted prices:
There-
after
2008 2009 2010 2011 2012 (2)
---------------------------------------------------------------------
Edmonton Ref Price
($CDN/bbl)(1) 88.75 86.73 82.70 80.67 78.65 +2%
---------------------------------------------------------------------
AECO ($CDN/mmbtu) 6.80 7.28 7.43 7.58 7.73 +2%
---------------------------------------------------------------------
(1) Future prices incorporated a $1.00 US/CDN exchange rate.
(2) Percentage change of 2.0% represents the change in future prices
each year after 2012 to the end of the reserve life.
5. Long-Term Debt
The Trust has a syndicated $525 million extendible revolving credit
facility with a stated term date of April 30, 2008. 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
cash flow ratio that range from prime to prime plus 0.75% for debt to
earnings before interest, taxes, depreciation, depletion and
amortization (EBITDA) ratios ranging from less than 1:1 to greater
than 2.5:1. A General Security Agreement with a floating charge on
land registered in Alberta is held as collateral by the bank. The
average borrowing rate for 2007 was 5.7% (2006 - 5.0%).
6. Asset Retirement Obligations
The total future asset retirement obligations are estimated by
management based on the Trust's net ownership interest in all wells
and facilities, estimated costs to reclaim and abandon the wells and
facilities and the estimated timing of the costs to be incurred in
future periods. The Trust has estimated the net present value of its
total asset retirement obligations to be $6.8 million as at
December 31, 2007 (2006 - $5.8 million) based on a total future
liability of $25.9 million (2006 - $23.1 million). These payments are
expected to be made over the next 50 years. The Trust's credit
adjusted risk free rate of 7% and an inflation rate of 2% were used
to calculate the present value of the asset retirement obligations.
The following table reconciles the change in asset retirement
obligations:
($000) 2007 2006
---------------------------------------------------------------------
Balance, beginning of year 5,767 4,729
Increase in liabilities 581 686
Accretion expense 418 352
---------------------------------------------------------------------
Balance, end of year 6,766 5,767
---------------------------------------------------------------------
---------------------------------------------------------------------
7. Unitholders' Capital
Authorized: Unlimited number of voting trust units
Issued and Outstanding
Trust Units (no par value) ($000) Number of Units Amount
---------------------------------------------------------------------
Balance, December 31, 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, December 31, 2007 105,712,364 406,301
---------------------------------------------------------------------
---------------------------------------------------------------------
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.
Units to be Issued
At December 31, 2007, there were no trust units to be issued. On
December 31, 2006 the Trust completed a private placement of 285,190
trust units to employees and consultants for net proceeds of
$5,042,159. These trust units were issued on January 12, 2007.
Per Unit Amounts
Earnings per unit have been calculated based upon the weighted
average number of units outstanding during the year of 105,712,364
(2006 - 104,554,325). There are no dilutive instruments outstanding.
Redemption of Units
The Trust Units are redeemable at any time on demand by the holders
thereof. Upon receipt of proper notice to redeem Trust Units by the
Trust, the holder thereof shall only be entitled to receive a price
per Trust Unit equal to the lesser of:
(a) 90% of the market price of the Trust Units on the principal
market on which the Trust Units are quoted for trading during the 10
trading day period commencing immediately after the date on which the
Trust Units are tendered to the Trust for redemption; and
(b) the closing market price on the principal market on which the
Trust Units are quoted for trading on the date that the Trust Units
are so tendered for redemption.
8. Accumulated Cash Distributions
During the year, the Trust paid distributions to the unitholders in
the aggregate amount of $177.5 million (2006 - $173.8 million total;
$158.2 million cash) 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 14, 2007 $0.14
July 2007 July 31, 2007 August 15, 2007 $0.14
August 2007 August 31, 2007 September 15, 2007 $0.14
September 2007 September 30, 2007 October 13, 2007 $0.14
October 2007 October 31, 2007 November 15, 2007 $0.14
November 2007 November 30, 2007 December 15, 2007 $0.14
December 2007 December 31, 2007 January 15, 2008 $0.14
Accumulated Earnings and Distributions
($000) 2007 2006
---------------------------------------------------------------------
Opening accumulated earnings 531,154 335,926
Net earnings for the year 208,884 195,228
---------------------------------------------------------------------
Total accumulated earnings 740,038 531,154
Total accumulated distributions (622,466) (444,918)
---------------------------------------------------------------------
Accumulated earnings 117,572 86,236
---------------------------------------------------------------------
9. 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.
($000) 2007 2006
Field expenses 28,433 25,765
Processing and gathering income (9,074) (7,719)
---------------------------------------------------------------------
Total operating costs 19,359 18,046
---------------------------------------------------------------------
---------------------------------------------------------------------
10. General and Administrative Expenses
General and administrative expenses are reduced by operating and
capital overhead recoveries from operated properties.
($000) 2007 2006
---------------------------------------------------------------------
General and Administrative expenses 10,242 9,397
Overhead recoveries (3,117) (5,431)
---------------------------------------------------------------------
Net General and Administrative expenses 7,125 3,966
---------------------------------------------------------------------
11. Performance Based Compensation
The Trust awards performance based compensation to employees and key
consultants annually. The performance based compensation is comprised
of market and reserve value based components.
The reserves value based component is 4% of the incremental increase
in value, if any, as adjusted to reflect changes in debt, equity and
distributions, of proved producing reserves calculated using a
constant price at December 31 of the current year and a discount rate
of 8%.
---------------------------------------------------------------------
($millions except unit values) 2007 2006 Change
---------------------------------------------------------------------
Net present value of proved producing
reserves @ 8% based on constant
Paddock Lindstrom 2008 price
forecast 1,725.0 1,708.0
Net debt before performance based
compensation (450.3) (433.6)
2007 distributions - (177.5)
-------------------------------
Net value 1,274.7 1,096.9 177.8
Equity adjustment factor(x) 100%
---------
Equity adjusted increase in value 177.8
---------
2007 reserve value based compensation
@ 4% 7.1
---------------------------------------------------------------------
---------------------------------------------------------------------
(x) Equity adjustment factor is calculated as the percent increase in
value per unit divided by the total percent increase in value
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 2008, a tax factor of
1.333 will then be applied to determine the amount to be paid.
Commencing for rights vesting in 2009, no tax factor will be applied
to determine the amount paid. The 2007 market based component was
based on 1.2 million vested rights at an average grant price of
$24.16, average cumulative distributions of $4.73 and the five day
weighted average closing price of $16.48 (2006 - 1.5 million rights,
average grant price of $18.77, average cumulative distributions of
$3.86 per unit and five day weighted average closing price of
$17.68).
The total amount expensed under these plans was as follows:
($000) 2007 2006
Market based compensation 13 8,491
Reserve value based compensation 7,120 4,570
Recovery of prior year unpaid reserve bonus - (750)
---------------------------------------------------------------------
Total 7,133 12,311
---------------------------------------------------------------------
---------------------------------------------------------------------
For the future market based component, compensation costs as at
December 31, 2007 related to 3.0 million non-vested rights with an
average grant price of $21.04 were $0.3 million (2006 - nil).
12. Future Income Taxes
($000) 2007 2006
---------------------------------------------------------------------
Earnings before income taxes 196,431 222,423
Statutory income tax rate 32.12% 36.75%
---------------------------------------------------------------------
Expected income taxes 63,094 81,740
Increase (decrease) in income taxes from:
Non-deductible crown charges - 10,328
Resource allowance - (11,812)
Corporate income tax rate change (21,357) (2,397)
Income attributed to the trust (51,933) (50,823)
Change in valuation allowance for share
issue costs (1,000) 1,000
Other (1,257) (679)
---------------------------------------------------------------------
Future income tax expense (12,453) 27,357
---------------------------------------------------------------------
---------------------------------------------------------------------
The net future income tax liability is
comprised of:
($000) 2007 2006
---------------------------------------------------------------------
Financial derivative assets 2,285 -
---------------------------------------------------------------------
Current future income taxes 2,285 -
---------------------------------------------------------------------
---------------------------------------------------------------------
Differences between tax base and reported
amounts for depreciable assets 124,973 137,322
Accrued expenditures (85) -
Provision for asset retirement obligation (1,691) (1,672)
---------------------------------------------------------------------
Future income taxes 123,197 135,650
---------------------------------------------------------------------
---------------------------------------------------------------------
At December 31, 2007 the Trust has tax pools of approximately
$660.1 million (December 31, 2006 - $670.8 million) available for
deduction against future income. The Trust has approximately
$2.0 million in unrecognized future income tax assets available to
reduce future taxable income.
13. Financial Instruments
The following summarizes the retrospective without restatement
adoption adjustments that were required as at January 1, 2007.
December 31, 2006 Adoption January 1, 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
December 31, 2007 is as follows:
Weighted
Crude Oil Daily Average
Period Hedged Type Volume Price (CAD)
---------------------------------------------------------------------
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
Natural Gas Daily Average
Period Hedged Type Volume Price (CAD)
---------------------------------------------------------------------
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 to October 31, 2008 Fixed price 5,000 GJ $6.60/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
Nov 1, 2008 to March 31, 2009 Fixed price 5,000 GJ $7.60/GJ
As at December 31, 2007, the Trust had committed to the future sale
of 45,500 barrels of crude oil at an average price of $78.85 per
barrel and 12,465,000 gigajoules (GJ) of natural gas at an average
price of $7.34 per GJ or $8.59 per mcf based on the historical
heating value of Peyto's natural gas. These contracts will generate
revenue totaling $95.1 million. Based on the market's estimate of the
future commodity prices as at December 31, 2007 the fair value of
these contracts would be $87.7 million. Had these contracts been
closed on December 31, 2007, the Trust would have realized a gain in
the amount of $7.4 million.
Subsequent to December 31, 2007 the Trust entered into the following
contracts:
Natural Gas Daily Price
Period Hedged Type Volume (CAD)
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April 1 to October 31, 2008 Fixed price 5,000 GJ $6.80/GJ
April 1 to October 31, 2008 Fixed price 5,000 GJ $7.05/GJ
April 1 to October 31, 2008 Fixed price 5,000 GJ $7.20/GJ
April 1 to October 31, 2008 Fixed price 5,000 GJ $7.10/GJ
April 1 to October 31, 2008 Fixed price 5,000 GJ $7.20/GJ
April 1 to October 31, 2008 Fixed price 5,000 GJ $7.40/GJ
April 1, 2008 to March 31, 2009 Fixed price 5,000 GJ $7.05/GJ
Nov 1, 2008 to March 31, 2009 Fixed price 5,000 GJ $8.00/GJ
Nov 1, 2008 to March 31, 2009 Fixed price 5,000 GJ $8.25/GJ
Nov 1, 2008 to March 31, 2009 Fixed price 5,000 GJ $8.40/GJ
Nov 1, 2008 to March 31, 2009 Fixed price 5,000 GJ $8.65/GJ
Fair Values of Financial Assets and Liabilities
The Trust's financial instruments include cash, accounts receivable,
due from private placements deposits, current liabilities, provision
for future performance based compensation and long-term debt. At
December 31, 2007, the carrying value of cash, accounts receivable,
due from private placements deposits, current liabilities excluding
future income tax and provision for future performance based
compensation approximate their 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
December 31, 2007, approximately 31% was due from one company
(December 31, 2006 - 41%). Of the Trust's revenue for the year ended
December 31, 2007 approximately 57% was received from two companies
(December 31, 2006 - 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 due to the floating rate
nature of the interest expense on its revolving demand facility.
14. Supplemental Cash Flow Information
Changes in non-cash working capital balances
($000) 2007 2006
---------------------------------------------------------------------
Accounts receivable 5,690 29,376
Due from private placement 5,042 22,408
Prepaid expenses and deposits (2,339) (886)
Accounts payable and accrued liabilities 15,087 (137,448)
Capital taxes payable - (110)
Cash distributions payable 64 3,205
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23,544 (83,455)
Attributable to financing activities 5,107 25,613
Attributable to investing activities 2,222 (71,579)
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Attributable to operating activities 16,215 (37,489)
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2007 2006
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Cash interest paid during the year 23,007 18,011
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15. Contingencies and Commitments
a) Contingent Liability
From time to time, Peyto is the subject of litigation arising out of
its day-to-day operations. Damages claimed pursuant to such
litigation, including the litigation discussed below, may be material
or may be indeterminate and the outcome of such litigation may
materially impact Peyto's financial position or results of operations
in the period of settlement. While Peyto assesses the merits of each
lawsuit and defends itself accordingly, Peyto may be required to
incur significant expenses or devote significant resources to
defending itself against such litigation. These claims are not
currently expected to have a material impact on Peyto's financial
position or results of operations. Peyto has been named in a
Statement of Claim issued by Canadian Natural Resources Limited and
affiliates ("CNRL"), claiming $13 million in damages for alleged
breaches of duty as operator of jointly owned properties, and an
interim and permanent injunction to prevent Peyto from proceeding
with the completion of a well on those properties. CNRL alleges that
Peyto failed to take proper steps as operator of a joint well (the
"Well") on lands that offset 100% Peyto owned lands. Peyto has filed
a Statement of Defense defending the allegations set forth in the
Statement of Claim. The injunction claimed by CNRL was to prevent
Peyto from completing the Well at a target location which had been
agreed upon by both parties. Although claimed in the Statement of
Claim, CNRL did not apply for an interim injunction, and Peyto
completed the Well as planned, but no commercial production was
obtained. Affidavits of Records were filed in July, 2006 but CNRL had
taken no steps to move the matter forward until February 14, 2007
when it proposed to amend its Statement of Claim to add a subsidiary
as an additional Plaintiff and to particularize further its
allegations. Accordingly, it remains to be seen whether CNRL will
proceed with the action. If the action goes ahead, Peyto intends to
defend itself vigorously. Although the outcome of this matter is not
determinable at this time, Peyto believes that this claim will not
have a material adverse effect on the Trust's financial position or
results of operations.
b) Commitments
The Trust is committed to payments under operating leases for office
space as follows:
($000)
---------------------------------------------------------------------
2008 1,097
2009 1,097
2010 1,097
2011 1,097
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4,388
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16. 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. For the year ended December 31, 2007, legal fees
totaled $1,051,643 (2006 - $695,563). As at December 31, 2007, an
amount due to this firm of $844,191 was included in accounts payables
(2006 - $361,163)
17. Subsequent Event
On January 1, 2008, the Trust completed an internal reorganization,
whereby (1) all of the oil and gas assets of the Trust are now held
in the newly formed Peyto Energy Limited Partnership (the
"Partnership"), (2) Peyto Energy Administration Corp. is the
administrator of the Trust and POT and (3) Peyto is the general
partner of the Partnership. Certain subsidiaries of the Trust were
amalgamated pursuant to the internal reorganization.
Peyto Exploration & Development Corp. Information
Officers
Darren Gee Scott Robinson
President and Chief Executive Officer Executive Vice
President and Chief
Operating Officer
Glenn Booth Kathy Turgeon
Vice President, Land Vice President, Finance
and Chief Financial
Officer
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
Head Office
2900, 450 - 1st Street SW
Calgary, AB
T2P 5H1
Phone: 403.261.6081
Fax: 403.451.4100
Web: www.peyto.com
Stock Listing Symbol: PEY.un
Toronto Stock Exchange
%SEDAR: 00019597E