SYMBOL: PEY.UN - TSX
CALGARY, March 7 /CNW/ - Peyto Energy Trust ("Peyto") is a leader in the exploration and development of natural gas in western Canada. By design, our core areas are located in Alberta's premier gas exploration area, the Deep Basin. We are known for our high quality assets, our low cost structure and our ability to profitably find and develop new oil and natural gas reserves, year after year. We are proud to present our operating and financial results for the fourth quarter and 2006 fiscal year.
The following summarizes certain of the Trust's attributes at year end.
- Long reserve life - Proved Producing 12 years, Total Proved 14 years,
Proved plus Probable 20 years
- High netback - $39.25/boe
- Low operating costs - $2.16/boe
- Low base general and administrative costs - $0.48/boe
- High operatorship - over 95% of production
- Low cash distribution ratio - 57% of fourth quarter 2006 funds from
operations
- Low debt to funds from operations ratio - 1.4 (net debt, before
provision for future performance based compensation, divided by
annualized fourth quarter 2006 funds from operations)
- Distribution growth - distributions have been increased 5 times,
never decreased, and are now 87% higher than when the trust was
formed three and a half years ago
- Transparent capital structure - no convertible debentures, no
exchangeable shares, no stock options, no warrants
The following summarizes certain performance highlights for the year.
- Value creation - invested $312 million in capital and created
$914 million of Proved Producing and $1,197 million worth of Proved
plus Probable undiscounted reserve value, translating into NPV
recycle ratios of 2.9 and 3.8 respectively
- Asset value growth - the debt adjusted net present value of the
trust's Proven plus Probable oil and gas assets, discounted at 5%,
grew by 9% per trust unit to $30.75 in 2006
- Reserve growth per unit - proved producing reserves, grew 8% year
over year
- Reserve life growth - Proven Producing reserve life grew from 11
years in 2005 to 12 years in 2006, while Proven plus Probable reserve
life grew from 19 to 20 years.
- Distributions per unit - increased by 19% from $1.39 in 2005 to $1.66
in 2006.
- Distribution life growth - increased from 19 years in 2005 to
23 years in 2006 (based on undiscounted proven producing NPV and as
defined herein)
- Annual production growth - increased 3% from 22,219 boe/d in 2005 to
22,873 boe/d in 2006
- Annual production per unit(1) - increased 1% year over year but
decreased 9% per debt adjusted unit
- Annual funds from operations per unit(1) - increased 1% year over
year but decreased 9% per debt adjusted unit
- Cost of new reserves (FD&A) - Proved Producing $17.67/boe, Total
Proved $19.66/boe, Proved Plus Probable $17.39/boe (including change
in future development capital)
- Recycle ratio - Proved Producing 2.0, Total Proved 1.8, Proved Plus
Probable 2.0 (including change in future development capital)
- Reserve replacement - Proved Producing 211%, Total Proved 194%,
Proved Plus Probable 220%
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 $17.70 for 2006
and $25.39 for 2005.
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3 Months Ended 12 Months Ended
Dec. 31 % Dec. 31 %
2006 2005 Change 2006 2005 Change
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Operations
Production
Natural gas
(mcf/d) 112,296 108,356 4% 112,751 106,701 6%
Oil & NGLs
(bbl/d) 3,834 4,185 (8)% 4,081 4,436 (8)%
Barrels of
oil equiv-
alent (boe/d
at 6:1) 22,550 22,245 1% 22,873 22,219 3%
Product prices
Natural gas
($/mcf) 8.84 10.55 (16)% 8.46 8.78 (4)%
Oil & NGLs
($/bbl) 54.89 58.43 (6)% 61.00 55.48 10%
Operating
expenses
($/boe) 2.69 1.95 38% 2.16 1.55 39%
Transportation
($/boe) 0.52 0.70 (26)% 0.58 0.68 (15)%
Field netback
($/boe) 40.85 43.33 (6)% 39.25 37.83 4%
General &
administrative
expenses
($/boe) 0.85 0.05 1600% 0.48 0.08 500%
Interest expense
($/boe) 2.72 0.91 199% 2.16 1.07 102%
Financial ($000,
except per
unit)
Revenue 110,696 127,633 (13)% 439,008 431,695 2%
Royalties
(net of ARTC) 19,271 33,522 (43)% 88,446 106,802 (17)%
Funds from
operations 77,360 86,607 (11)% 305,845 296,970 3%
Funds from
operations
per unit 0.74 0.85 (13)% 2.93 3.01 (3)%
Total
distributions 44,206 36,773 20% 173,755 136,648 27%
Total
distributions
per unit 0.42 0.36 17% 1.66 1.39 19%
Payout ratio 57 42 36% 57 46 24%
Cash
distributions
(net of DRIP) 44,206 33,771 31% 158,204 127,094 24%
Payout ratio 57 39 46% 52 43 21%
Earnings 47,012 60,745 (23)% 195,228 161,568 21%
Earnings per
diluted unit 0.44 0.60 (27)% 1.86 1.64 13%
Capital
expenditures 28,413 107,647 (74)% 311,926 358,454 (13)%
Weighted
average trust
units outstan-
ding 105,251,394 102,148,411 3% 104,554,325 98,576,640 6%
As at
December 31
Net debt
(before future
compensation
expense) 426,356 287,885 48%
Unitholders'
equity 489,712 421,831 16%
Total assets 1,136,700 944,927 20%
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Net Earnings 195,228 161,568
Items not requiring cash:
Provision for (recovery of) performance
based compensation (10,149) (18,271)
Future income tax expense 27,357 37,618
Depletion, depreciation and accretion 81,098 58,208
Non-recurring items:
Performance based compensation 12,311 57,847
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Funds from operations(1) 305,845 296,970
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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. We believe that funds from operations is an important parameter to measure the value of an asset when combined with reserve life. Funds from operations is not a measure recognized by Canadian generally accepted accounting principles ("GAAP") and does not have a standardized meaning prescribed by GAAP. Therefore, funds from operations, as defined by Peyto, may not be comparable to similar measures presented by other issuers, and investors are cautioned that funds from operations should not be construed as an alternative to net earnings, cash flow from operating activities or other measures of financial performance calculated in accordance with GAAP. Funds from operations cannot be assured and future distributions may vary.
Year in Review
Peyto is a conventional style energy company with unconventional assets and uncommon results. We explore for new reserves. We develop what we find. We operate what we produce. We sell our production and deliver part of the income to our unitholders while deploying the remaining capital to repeat this process and grow our asset base. Acquiring what others have found and developed has not yet met our rate of return objectives; the margins are just too thin. Funding additional exploration activity with equity or debt is fine, so long as the cost of this capital does not impair our returns or dilute our unitholders. We will continue to operate our business in this way regardless of our organizational structure. Our structure will adapt and evolve to ensure our income is distributed in the most tax efficient manner possible.
By all measures, 2006 was a challenging year. Natural gas prices (AECO monthly) changed dramatically throughout the year dropping 63% from highs of $11.48/GJ in January to lows of $4.22/GJ in October. In contrast, service costs continued to rise with CAODC (Canadian Association of Oilwell Drilling Contractors) labor rates increasing again in October 2006. The Finance Minister's announcement on October 31, 2006, relating to the taxation of trusts, sent unit prices tumbling. Navigating through these challenges tested our business strategy to its fullest. We recognized early in the year that, for the first time, our rates of return on capital invested were beginning to diminish. This was in part driven by declining commodity prices relative to increased service costs and in part due to a pace of development that was too aggressive. A conscious decision was made to slow down our pace of investment and refocus our attentions on those opportunities that delivered a premium return in this environment. This approach worked. Our FD&A costs and internal rates of return improved and are continuing to improve as illustrated in the following table.
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2006
Full Cycle Investment Analysis Q1 Q2 Q3 Q4
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FD&A (Proved Producing, $/boe) $19.35 $16.34 $15.27 $14.57
Internal Rate of Return (IRR) 17% 30% 39% 47%
Capital Expenditures ($ millions) $145 $67 $71 $28
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(x) Peyto internal evaluation based on actual well related capital spent
(inclusive of land, seismic and facilities) and using Paddock
Lindstrom and Associates reserve assignments and price forecasts.
Peyto was able to adapt to these changing business conditions without compromising our strategy or cutting our distribution. Our internal standards for investment return remain as high as ever and we continually monitor our investment results to ensure we are meeting these expectations. We have emerged from 2006 with even more confidence that our focused approach, designed for managed growth and increased sustainability, continues to succeed.
Peyto has now achieved a milestone in its history. For the first time, we are operating solely on our internally generated capital, having delivered all of the unitholder's equity back in distributions. Since Peyto's inception, we have invested a total of $1.3 billion in capital, raised $404 million in unitholder's equity, distributed $445 million in distributions, and built an asset that is worth $3.7 billion ($3.3 billion after adjusting for debt, P+P NPV(5)). Unfortunately, this does not mean that all unitholders have enjoyed their fair share of returns. At times our unit price has reflected our value, at other times it has not. What it does mean, however, is that our long life, low cost natural gas business has invested significantly less than the value we have created. We will continue to use our technical expertise and our ability to execute our ideas to create future wealth for our unitholders.
As illustrated in the following table, cash flow generated from our investments has played a dominant role, while net equity has played a relatively minor role in funding of our capital expenditures since Peyto's inception eight years ago.
------------------------------------------------------------------------- Funding Sources for Capital Since Inception (from 1998 to 2006) ($000) % of Total ------------------------------------------------------------------------- Cash flow from projects found and developed by Peyto 898,928 70% Net Equity (Equity issued of $403.5 million less Accumulated Distributions of $444.9 million) (41,442) (3)% Net Debt (year end 2006 excluding future performance based compensation) 426,356 33% ------------------------------------------------------------------------- Total Capital Expenditures 1,283,842 100% ------------------------------------------------------------------------- -------------------------------------------------------------------------
Capital Expenditures
Net capital expenditures for 2006 totaled $312 million which was a decrease of 13% from 2005 reflecting a slow down in activity level in response to service cost inflation. Consistent with our "design, drill and build" strategy, 100% of the capital was invested to develop and produce new oil and gas reserves in Alberta's Deep Basin. Investment in processing facilities in the Wildhay and Nosehill areas accounted for $26 million and added 40 mmcf/d of additional gas plant capacity. Future drilling inventory was secured with an additional investment of $22 million in land and seismic. None of our 2006 capital was spent on acquisitions. The following table summarizes capital expenditures for the year.
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2006 2005 Since Inception
Capital % of % of % of
Expenditures ($000) Total ($000) Total ($000) Total
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Land 13,253 4% 12,324 3% 40,966 3%
Seismic 8,944 3% 11,559 3% 33,257 3%
Drilling &
Completion -
Exploratory &
Development 227,585 73% 274,360 77% 929,527 72%
Production
Equipment,
Facilities &
Pipelines 61,961 20% 59,810 17% 248,195 19%
Acquisitions &
Dispositions - - - - 30,856 3%
Office Equipment 183 - 401 - 1,040 -
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Total 311,926 100% 358,454 100% 1,283,842 100%
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During the year, we drilled or re-entered 82 gross (66 net) gas wells. The average depth of our wells increased another 46m to 2606m, as our drilling prospects continue to evolve to include deeper Cretaceous zones. Most of our wells have at least two and sometimes three prospective gas bearing zones for development.
Reserves
During 2006, the trust was again successful in adding high quality, long life reserves through the drill bit. The following table illustrates the change in reserve volumes and net present value of future cash flow, discounted at 5%, before income tax using variable pricing.
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As at December 31
% Change
Per Unit
(NPV(5)
% debt
2006 2005 Change adjusted)
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Reserves
BOE 6:1 (mstb)
Proved Producing 97,181 87,881 11% 8%
Total Proved 118,681 110,802 7% 5%
Proved + Probable Additional 163,464 153,448 7% 4%
Net Present Value ($million)
Discounted at 5%
Proved Producing 2,462 2,113 17% 14%
Total Proved 2,869 2,539 13% 11%
Proved + Probable Additional 3,679 3,219 14% 12%
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Note: Based on the Paddock Lindstrom & Associates report effective
December 31, 2006. The Paddock Lindstrom and Associates Ltd. price
forecast is available at www.padlin.com. For more information on Peyto's
reserves, we refer you to our Press Release dated February 14, 2007
announcing our 2006 Year End Reserve Report which is available on our
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 2007.
Value Creation
At Peyto we believe that value creation is the fundamental measure of our investment success. We quantify this by measuring the value created during the year compared to the capital invested, and do so to ensure the most efficient use of the unitholders' capital on a go forward basis. At Peyto's request and for the benefit of unitholders, the independent engineers have run last year's Net Present Value (NPV) with this year's price forecast to eliminate the change in value attributable to the commodity prices. This approach isolates the value created by the Peyto team from the value created by the change in commodity prices. In 2006, we created $914 million of Proved Producing and $1,197 million of Proved plus Probable undiscounted reserve value with $312 million in capital. Relative to our enterprise value, this amount of net value created represents a significant growth rate. The following table breaks out the value created by Peyto's capital investments and reconciles the changes in debt adjusted NPV of future net revenues using forecast prices and costs as at December 31, 2006.
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Proven +
Proven Total Probable
Producing Proven Additional
($millions)
Discounted at 0% 5% 0% 5% 0% 5%
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Net Present Value at
Beginning of Year
($millions) $3,248 $1,816 $4,075 $2,242 $5,709 $2,922
Dec. 31, 2005 Evaluation
using PLA Jan. 1, 2006
price forecast, debt
adjusted
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Per Unit Outstanding
at Dec. 31, 2005
($/unit) $31.40 $17.55 $39.39 $21.76 $55.18 $28.24
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2006 sales (revenue
less royalties and
operating costs) ($328) ($328) ($328) ($328) ($328) ($328)
Net Change due to
price forecasts
(using PLA Jan 1,
2007 price forecast) $232 $49 $298 $64 $481 $114
Net Change due to
discoveries
(additions,
extensions, transfers,
revisions) $914 $491 $915 $457 $1,197 $537
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Net Present Value at End
of Year ($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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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. We believe that the value analysis presented above is the best measure of profitability, as it compares the value of what was created relative to what was invested, or what we term, the Net Present Value (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 2006 our Proven plus Probable NPV recycle ratio was 3.8 times, up from 3.2 times in 2005. This means for each dollar we invested we were able to create 3.8 new dollars of Proven plus Probable reserve value.
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Dec 31, Dec 31,
2006 Value Creation 2006 2005 % Change
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NPV Recycle Ratio
Proven Producing 2.9 2.5 17%
Total Proven 2.9 2.8 6%
Proven + Probable 3.8 3.2 19%
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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.
We present other measures for comparative purposes, such as FD&A, recycle ratio and reserve replacement ratio, but caution that they are incomplete and on their own do not measure success.
For the second year in a row, our reserves grew faster than our production. This resulted in an increase in reserve life for all of the reserve categories. Our Proven plus Probable reserve life grew from 19 years at the end of 2005 to 20 years at the end of 2006. Along with this reserve life growth was a growth in the assets that fund distributions. Our distribution life grew from 19 years to 23 years for the Proved Producing category, increasing our sustainability.
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Proved Total Proved +
2006 Performance Ratios Producing Proved Probable
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Reserve life index (years)
Q4 2006 average production -
22,550 boe/d 12 14 20
Finding, development and acquisition
costs ($/boe) (Including change in
future development capital) $17.67 $19.66 $17.39
Reserve replacement ratio 2.1 1.9 2.2
Recycle ratio
(Including change in future
development capital) 2.0 1.8 2.0
Distribution life (years) 23 28 40
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- 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 97,181/(22.550(x)365)(equal sign)12).
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 annualized production. In our opinion,
for comparative purposes, the proved developed producing reserve life
provides the best measure of sustainability.
- 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 by the change in the reserves, including
revisions, for the same period. Subsequent to NI 51-101 in 2003, FD&A
costs are calculated including the change in future development
capital ("FDC") (eg. Proved Producing (equal sign) $312MM/17.65mmboes
(equal sign) $17.67/boe).
- The reserve replacement ratio is determined by dividing the yearly
change in reserves before production by the actual annual production
for the year (eg. Proved Producing ((97,181-87,881+8,350)/8,350)
(equal sign)2.1).
- Recycle ratio is calculated by dividing the field net back per boe,
before hedging, by the FD&A costs for the period (eg. Proven
Producing ($39.25/boe-$4.53/boe)/$17.67/boe (equal sign) 2.0). In our
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 to find new reserves it may not
accurately indicate investment success.
- The distribution life is calculated by dividing the debt adjusted
undiscounted NPV by the Q4 annualized distribution (eg. Proved
Producing $4,066 million/(44.2(x)4) million/year (equal sign)
23 years).
Quarterly Review
Daily production for the three months averaged 112 mmcf of natural gas and 3,834 barrels of oil and natural gas liquids. Reductions in production and commodity prices decreased funds from operations from $86.6 million in Q4 2005 to $77.4 million in Q4 2006. Peyto's commodity prices, net of hedging, decreased by 16% to average $8.84 per mcf of natural gas, and by 6% to average $54.89 per barrel of oil and natural gas liquids. The high heating value of our gas resulted in a 17% premium when converted from gigajoules at the AECO price hub to mcf at the plantgate.
Operating costs averaged $2.69/boe in the fourth quarter of 2006 compared to $1.95/boe for the fourth quarter of 2005. Cost inflation was observed for two main components of our cost structure; chemicals and labor. Methanol, which comprises approximately 20% of our costs, increased by 50% over the course of the year. In addition, labor costs also increased with the elevated level of industry activity. In our estimation, any increase in operating costs due to a maturing producing base will be more than offset by a reduction in the royalty rate, resulting in a higher netback per boe. Peyto continues to have the lowest operating costs in the trust sector by a significant margin.
Capital expenditures for the quarter totaled $28.4 million, the lowest for the period since 2001, reflecting our dramatic slow down of activity in response to continued service cost inflation. Only our premium opportunities attracted our capital dollars. As usual, well related activity made up 94% of this capital, with drilling and completion costs accounting for $22.8 million while facilities and tie-ins accounted for $5.0 million. Peyto spent $0.5 million on land and seismic in the quarter.
Activity Update
Peyto has entered 2007 with a measured approach to capital spending as service sector costs remain too high relative to commodity prices. Over the first quarter of 2007, we expect to continue our present pace of capital spending which we currently anticipate will be less than retained cash flow. At this time, we are employing 3 drilling rigs targeting our premium quality opportunities. We stand poised with over 100 drill ready locations and can increase our activity level quickly when we see a reduction in service costs or an increase in commodity prices.
To date in 2007, we have drilled and cased 8 gross gas wells (5.4 net) with very positive results. Drilling has focused in the Greater Sundance area where we have a high concentration of low risk multi-zone development opportunities. Thus far, we have connected and brought onstream 5.8 net wells (10.7 net zones). The 2007 new wells have begun to replace the natural decline of our base production with current production around the 22,000 boed level. In addition to Sundance, recent drilling in two new expansion areas called Pine Creek and Chime follow up successful discoveries and continue to seed our future.
Marketing
By design, Peyto's marketing strategy smoothes out short term fluctuations in the price of both natural gas and natural gas liquids through future sales. We do this by selling approximately 30% of our gas, net of royalties, on the daily and monthly spot markets while the other 70% is hedged. Our hedging is 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 we expect to break even on our forward sales (cum to date - $6 million gain). Our hedging approach is based on a forward average price typically made up of fifteen to twenty transactions placed over a 12 month period. Peyto sells its contracts in either the 7 month summer or the 5 month winter season.
Our natural gas price before hedging averaged $7.08/mcf during the fourth quarter of 2006, a decrease of 44% from $12.60/mcf reported for the equivalent period in 2005. Oil and natural gas liquids prices averaged $51.60/bbl down 18% from $63.27/bbl a year earlier. Hedging activity for the fourth quarter of 2006 increased Peyto's achieved price by $9.30/boe. The fourth quarter hedging gain was $19.3 million, for a year to date total gain of $37.8 million (2005 hedging loss $39.6 million). The following table shows commodity prices and revenue before and after hedging.
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Commodity Prices Three Months ended Twelve Months ended
Dec. 31 Dec. 31
2006 2005 2006 2005
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Natural gas ($/mcf) 7.08 12.60 7.50 9.62
Hedging - gas ($/mcf) 1.76 (2.05) 0.96 (0.84)
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Natural gas - after hedging ($/mcf) 8.84 10.55 8.48 8.78
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Oil and natural gas liquids ($/bbl) 51.60 63.27 62.11 59.62
Hedging - oil ($/bbl) 3.29 (4.84) (1.12) (4.14)
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Oil and natural gas liquids -
after hedging ($/bbl) 54.89 58.43 60.99 55.48
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Total Hedging ($/boe) 9.30 (10.93) 4.53 (4.88)
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Three Months ended Twelve Months ended
Revenue Dec. 31 Dec. 31
($000) 2006 2005 2006 2005
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Natural gas 73,192 125,651 308,692 374,750
Oil and natural gas liquids 18,200 24,359 92,523 96,532
Hedging gain (loss) 19,304 (22,377) 37,793 (39,587)
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Total revenue 110,696 127,633 439,008 431,695
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As at December 31, 2006, Peyto had committed to the forward sale of 145,400 barrels of crude oil at an average price of $86.45 per barrel and 16.2 million gigajoules (GJ) of natural gas at an average price of $8.54 per GJ. Based on the historical heating value of Peyto's natural gas, the price per mcf of the forward sale will be $9.99, which is 18% higher than the price Peyto realized in 2006. If we realize the market's estimate for future commodity prices, as at December 31, 2006, this forward sale represents a 29% premium.
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 old 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 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 our market and reserve value based compensation plan is available on our website.
Total performance based compensation paid in 2006 was $12.3 million (market component - $8.5 million; reserve value component - $3.8 million). After the performance based compensation payments, private placements are offered to Peyto employees and consultants. Unlike typical option plans, the employees of Peyto have voluntarily chosen to re-invest 100% 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. We feel it is through ownership that Peyto's team is best aligned to unitholders.
Sustainable Distributions
As a growth oriented, sustainable trust, our primary objective is to grow our resources from which we generate sustainable distributions for our unitholders. We have now distributed a total of $444.9 million or $4.255 per unit (adjusted for 2 for 1 split) to our unitholders. Since converting to a trust, we have returned 55% of the unit price at time of conversion, while increasing the reserves per unit by 73% and the production per unit by 37%.
Outlook
For Peyto, 2007 is setting up to be an exciting year. We believe that the land and seismic acquired in 2006 will lead to the exploration and development of several new fields. New facilities that were ordered in 2005 and installed in 2006, in anticipation of a continued aggressive pace of development, now have idle capacity. We are well positioned with this available capacity to handle continued development and expansion of core areas. We remain poised to capitalize on service cost reductions that the industry is anticipating later this year. The total amount of capital we ultimately invest in 2007 will be driven, as always, by the number and quality of projects we generate. Capital will only be invested if it meets the long term objectives of the trust. The majority of our capital program will involve drilling, completion and tie-in of low risk development gas wells. Capital expenditures will continue to be funded with a combination of funds from operations, working capital, and bank lines. We will use equity only if it makes good sense to do so. The commodity prices continue to strengthen and our marketing program has already secured strong prices for the summer period.
We have now completed our eighth year as a developer of natural gas assets. We continue to execute the same strategy we began with in 1998. We believe there is more money to be made in the Canadian oil patch, and we plan to continue doing just that for our unitholders. If you understand the value of your own capital and are interested in understanding the value of Peyto, we suggest that you visit the Peyto website at www.peyto.com where you will find a wealth of information designed to educate and inform investors who understand value and real returns.
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.
- 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, due to the
effects of aggregation.
- 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 reserves 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 2006 fourth quarter and year end results on Thursday, March 8, 2007 at 9:00 a.m. Mountain Standard Time (MST), 11:00 a.m. Eastern Standard Time (EST). To participate, please call 1-416-644-3426 (Toronto area) or 1-866-250-4909 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 21216111 followed by the pound key. The replay will be available at 11:00 a.m. MST, 1:00 p.m. EST Thursday, March 8, 2007 until midnight EST on Thursday, March 15, 2007. The conference call can also be accessed through the internet at http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID(equal sign)1697080. The archived conference call will be available on the Peyto 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 29, 2006 at the Telus Convention Centre, Mcleod Hall A, 120 - 9th Avenue SE, Calgary, Alberta.
Darren Gee
President and Chief Executive Officer
March 7, 2007
Certain information set forth in this document and Management's Discussion and Analysis, including management's assessment of Peyto's future plans and operations, contains forward-looking statements. By their nature, forward-looking statements are subject to numerous risks and uncertainties, some of which are beyond these parties' control, including the impact of general economic conditions, industry conditions, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other industry participants, the lack of availability of qualified personnel or management, stock market volatility and ability to access sufficient capital from internal and external sources. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Peyto's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits that 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, 2006 and 2005. 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 7, 2007. Additional information about Peyto, including the most recently filed annual information form is available at www.sedar.com.
Certain information set forth in this Management's Discussion and Analysis, including management's assessment of the Trust's future plans and operations, contains forward-looking statements. By their nature, forward-looking statements are subject to numerous risks and uncertainties, some of which are beyond these parties' control, including the impact of general economic conditions, industry conditions, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other industry participants, the lack of availability of qualified personnel or management, stock market volatility and ability to access sufficient capital from internal and external sources. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Peyto's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits that Peyto will derive there from. Peyto disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
Management uses funds from operations to analyze the operating performance of its energy assets. In order to facilitate comparative analysis, funds from operations is defined throughout this report as earnings before performance based compensation, non-cash and non-recurring expenses. We believe that funds from operations is an important parameter to measure the value of an asset when combined with reserve life. Funds from operations is not a measure recognized by Canadian generally accepted accounting principles ("GAAP") and does not have a standardized meaning prescribed by GAAP. Therefore, funds from operations, as defined by Peyto, may not be comparable to similar measures presented by other issuers, and investors are cautioned that funds from operations should not be construed as an alternative to net earnings, cash flow from operating activities or other measures of financial performance calculated in accordance with GAAP. Funds from operations cannot be assured and future distributions may vary.
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).
Proposed Tax Legislation
On October 31, 2006, the Minister of Finance announced its proposal to amend the Income Tax Act (Canada) to apply a Distribution Tax on distributions from publicly-traded income trusts. Under the proposal, existing income trusts will be subject to the new measures commencing in their 2011 taxation year, following a four-year grace period. The Minister of Finance has issued a Notice of Ways and Means Motion to Amend the Income Tax Act, but it is not known at this time if or when the proposal will be enacted by Parliament. In simplified terms, under the proposed tax plan, income distributions will first be taxed at the trust level at a special rate estimated to be 31.5%. Income distributions to individual unitholders will then be treated as dividends from a Canadian corporation and eligible for the dividend tax credit. Income distributions to corporations resident in Canada will be eligible for full deduction as tax free intercorporate dividends. Tax-deferred accounts (RRSPs, RRIFs and Pension Plans) will continue to pay no tax on distributions. Non-resident unitholders will be taxed on distributions at the non-resident withholding tax rate for dividends. The net impact on Canadian taxable investors is expected to be minimal because they can take advantage of the dividend tax credit. However, as a result of the 31.5% Distribution Tax at the trust level, distributions to tax-deferred accounts will be reduced by approximately 31.5%, and distributions to non-residents will be reduced by approximately 26.5%. We are currently assessing the proposals and the potential implications to the Trust. We will continue to review structural alternatives to ensure that Peyto's structure is as efficient as possible.
OVERVIEW
Peyto is a Canadian energy trust involved in the development and production of natural gas in Alberta's deep basin. As at December 31, 2006, we had total proved plus probable reserves of 163.5 million barrels of oil equivalent with a reserve life of 20 years as evaluated by our independent petroleum engineers. Our production is weighted as to 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 our growing
inventory of drilling projects.
- Build an asset base which is made up of high quality long life
natural gas reserves.
Operating results over the last eight years indicate that we have successfully implemented these principles. Our 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.
-------------------------------------------------------------------------
Year Ended December 31 2006 2005 2004
($000 except per unit amounts)
-------------------------------------------------------------------------
Total revenue (before royalties) 439,008 431,695 300,501
Funds from operations 305,845 296,970 209,106
Per unit - basic(x) 2.93 3.01 2.28
Per unit - diluted(x) 2.93 3.01 2.28
Earnings (loss) 195,228 161,568 73,782
Per unit - basic(x) 1.86 1.64 0.805
Per unit - diluted(x) 1.86 1.64 0.805
Total assets 1,136,700 944,927 622,577
Total long-term debt 420,000 180,000 180,000
Cash distributions per unit(x) 1.66 1.39 1.02
-------------------------------------------------------------------------
(x) Note: prior periods restated for 2 for 1 split of trust units
completed May 31, 2005.
QUARTERLY FINANCIAL INFORMATION
-------------------------------------------------------------------------
2006
($000 except per unit amounts) Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
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(x) 0.74 0.69 0.74 0.76
Per unit - diluted(x) 0.74 0.69 0.74 0.76
Earnings (loss) 47,012 46,155 56,768 45,293
Per unit - basic(x) 0.44 0.44 0.54 0.44
Per unit - diluted(x) 0.44 0.44 0.54 0.44
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2005
($000 except per unit amounts) Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Total revenue (net of royalties) 94,111 84,912 73,473 72,397
Funds from operations 86,607 77,179 66,548 66,636
Per unit - basic(x) 0.85 0.78 0.69 0.69
Per unit - diluted(x) 0.85 0.78 0.69 0.69
Earnings (loss) 60,745 37,702 25,690 37,431
Per unit - basic(x) 0.60 0.38 0.27 0.39
Per unit - diluted(x) 0.60 0.38 0.27 0.39
-------------------------------------------------------------------------
(x) Note: prior periods restated for 2 for 1 split of trust units
completed May 31, 2005.
RESULTS OF OPERATIONS
Production
-------------------------------------------------------------------------
Three Months ended Twelve Months ended
Dec. 31 Dec. 31
2006 2005 2006 2005
-------------------------------------------------------------------------
Natural gas (mmcf/d) 112,296 108,356 112,751 106,701
Oil & natural gas liquids (bbl/d) 3,834 4,185 4,081 4,436
Barrels of oil equivalent (boe/d) 22,550 22,245 22,873 22,219
-------------------------------------------------------------------------
Natural gas production averaged 112.3 mmcf/d in the fourth quarter of 2006, 4 percent higher than the 108.4 mmcf/d reported for the same period in 2005. Oil and natural gas liquids production averaged 3,834 bbl/d, a decrease of 8 percent from 4,185 bbl/d reported in the prior year. Production for the year increased 3 percent from 22,219 boe/d to 22,873 boe/d. The production increases are directly attributable to Peyto's ongoing drilling program and are offset by our natural decline rates.
Commodity Prices
-------------------------------------------------------------------------
Three Months ended Twelve Months ended
Dec. 31 Dec. 31
2006 2005 2006 2005
-------------------------------------------------------------------------
Natural gas ($/mcf) 7.08 12.60 7.50 9.62
Hedging - gas ($/mcf) 1.76 (2.05) 0.96 (0.84)
-------------------------------------------------------------------------
Natural gas - after hedging ($/mcf) 8.84 10.55 8.46 8.78
-------------------------------------------------------------------------
Oil and natural gas liquids ($/bbl) 51.60 63.27 62.11 59.62
Hedging - oil ($/bbl) 3.29 (4.84) (1.11) (4.14)
-------------------------------------------------------------------------
Oil and natural gas liquids -
after hedging ($/bbl) 54.89 58.43 61.00 55.48
-------------------------------------------------------------------------
Total Hedging ($/boe) 9.30 (10.93) 4.53 (4.88)
-------------------------------------------------------------------------
Our natural gas price before hedging averaged $7.08/mcf during the fourth quarter of 2006, a decrease of 44 percent from $12.60/mcf reported for the equivalent period in 2005. Oil and natural gas liquids prices averaged $51.60/bbl down 18 percent from $63.27/bbl a year earlier. Average natural gas prices for the year were down 22 percent at $7.50/mcf while oil and natural gas liquids prices were up 4 percent at $62.11/bbl compared to 2005. Hedging activity for fiscal 2006 increased Peyto's price achieved by $4.53/boe.
Revenue
-------------------------------------------------------------------------
Three Months ended Twelve Months ended
Dec. 31 Dec. 31
($000) 2006 2005 2006 2005
-------------------------------------------------------------------------
Natural gas 73,192 125,651 308,692 374,750
Oil and natural gas liquids 18,200 24,359 92,523 96,532
Hedging gain (loss) 19,304 (22,377) 37,793 (39,587)
-------------------------------------------------------------------------
Total revenue 110,696 127,633 439,008 431,695
-------------------------------------------------------------------------
For the three months ended December 31, 2006, gross revenue decreased 13 percent to $110.7 million from $127.6 million for the same period in 2005. The decrease in revenue for the quarter was a result of weaker commodity prices and decreased production volumes for oil and NGL. Revenues for the year increased due to increased gas volumes, as detailed in the following table.
-------------------------------------------------------------------------
Three Months ended Twelve Months ended
Dec. 31 Dec. 31
2006 2005 $million 2006 2005 $million
-------------------------------------------------------------------------
Total Revenue,
Dec 31, 2005 127.6 431.7
-------------------------------------------------------------------------
Revenue change due to:
-------------------------------------------------------------------------
Natural gas
Volume (mmcf) 10,331 9,969 3.8 41,154 38,946 19.4
Price ($/mcf) $8.84 $10.55 (17.7) $8.46 $8.78 (13.1)
Oil & NGL
Volume (mbbl) 353 385 (1.8) 1,490 1,619 (7.2)
Price ($/bbl) $54.89 $58.43 (1.2) $61.00 $55.48 8.2
-------------------------------------------------------------------------
Total Revenue,
Dec 31, 2006 110.7 439.0
-------------------------------------------------------------------------
Royalties
We pay royalties to the owners of the mineral rights with whom we hold leases, including the provincial government of Alberta. Alberta gas crown royalties are invoiced on the Crown's share of production based on a monthly established Alberta Reference Price. The Alberta Reference Price is a monthly weighted average price of gas consumed in Alberta and gas exported from Alberta reduced for transportation and marketing allowances.
-------------------------------------------------------------------------
Three Months ended Twelve Months ended
Dec. 31 Dec. 31
2006 2005 2006 2005
-------------------------------------------------------------------------
Royalties, net of ARTC ($000) 19,271 33,522 88,446 106,802
% of sales 18 26 21 25
$/boe 9.29 16.38 10.59 13.17
-------------------------------------------------------------------------
For the fourth quarter of 2006, royalties averaged $9.29/boe or approximately 18 percent of Peyto's total petroleum and natural gas sales. Year to date royalties were 21 percent of sales in 2006 compared to 25 percent in 2005. 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 our average per well production rate declines, the associated effective Crown Royalty rate will decrease. In addition, Peyto receives Deep Gas Royalty Holiday benefits and Alberta Royalty Tax Credits which further decrease our crown royalty rate.
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
2006 2005 2006 2005
-------------------------------------------------------------------------
Operating costs ($000)
Field expenses 7,361 5,347 25,765 17,609
Processing and gathering income (1,780) (1,354) (7,719) (5,063)
-------------------------------------------------------------------------
Total operating costs 5,581 3,993 18,046 12,546
-------------------------------------------------------------------------
$/boe 2.69 1.95 2.16 1.55
-------------------------------------------------------------------------
Transportation 1,089 1,433 4,856 5,520
-------------------------------------------------------------------------
$/boe 0.52 0.70 0.58 0.68
-------------------------------------------------------------------------
Operating costs were $5.6 million in the fourth quarter of 2006 compared to $4.0 million during the same period a year earlier. On a unit-of-production basis, operating costs averaged $2.69/boe in the fourth quarter of 2006 compared to $1.95/boe for the fourth quarter of 2005. Operating costs for the year averaged $2.16/boe in 2006 compared to $1.55/boe in 2005. Cost inflation during 2006 significantly impacted two main components of our cost structure: chemicals and labor. Transportation expense remained constant and was lower on a per boe basis.
Netbacks
Operating netbacks represent the profit margin associated with the production and sale of petroleum and natural gas. The primary factors that produce Peyto's strong netbacks are a low cost structure and the high heat content of our natural gas that results in higher commodity prices.
-------------------------------------------------------------------------
Three Months ended Twelve Months ended
Dec. 31 Dec. 31
($/boe) 2006 2005 2006 2005
-------------------------------------------------------------------------
Sale Price 53.35 62.36 52.58 53.23
Less:
Royalties 9.29 16.38 10.59 13.17
Operating costs 2.69 1.95 2.16 1.55
Transportation 0.52 0.70 0.58 0.68
-------------------------------------------------------------------------
Operating netback 40.85 43.33 39.25 37.83
General and administrative 0.85 0.05 0.48 0.08
Interest on long-term debt 2.72 0.91 2.16 1.07
Capital tax - 0.06 - 0.06
-------------------------------------------------------------------------
Cash netback 37.28 42.31 36.61 36.62
-------------------------------------------------------------------------
General and Administrative Expenses
-------------------------------------------------------------------------
Three Months ended Twelve Months ended
Dec. 31 Dec. 31
2006 2005 2006 2005
-------------------------------------------------------------------------
G&A expenses ($000) 2,426 1,874 9,397 6,434
Overhead recoveries (669) (1,778) (5,431) (5,754)
-------------------------------------------------------------------------
Net G&A expenses 1,757 96 3,966 680
-------------------------------------------------------------------------
$/boe 0.85 0.05 0.48 0.08
-------------------------------------------------------------------------
General and administrative expenses before overhead recoveries increased to $2.4 million in the fourth quarter of 2006, as compared to $1.8 million for the same period in 2005 due to an increase in staffing and associated costs. Net of overhead recoveries associated with our capital expenditures program, general and administrative costs increased to $0.85 per boe in the fourth quarter of 2006, from $0.05 per boe in the fourth quarter of 2005. Fourth quarter 2006 capital overhead recoveries were 61% lower than fourth quarter 2005 recoveries. General and administrative expenses for 2006 averaged $0.48/boe in 2006 compared to $0.08 in 2005. Peyto has decreased reliance on third party consulting and replaced these services with staff positions resulting in increased general and administrative costs. This strategy has resulted in an over-all cost decrease to the Trust.
Interest Expense
-------------------------------------------------------------------------
Three Months ended Twelve Months ended
Dec. 31 Dec. 31
2006 2005 2006 2005
-------------------------------------------------------------------------
Interest expense ($000) 5,638 1,857 18,011 8,702
$/boe 2.72 0.91 2.16 1.07
-------------------------------------------------------------------------
2006 interest expense was $18.0 million or $2.16/boe compared to $8.7 million or $1.07/boe a year earlier. Average bank debt for 2006 was $360 million as compared to $221 million for 2005. Interest rates continue to be favorable and are not expected to increase substantially in the short-term.
Depletion, Depreciation and Accretion
The 2006 provision for depletion, depreciation and accretion totaled $81.1 million as compared to $58.2 million in 2005. On a unit-of-production basis, depletion, depreciation and accretion costs averaged $9.71/boe as compared to $7.18/boe in 2005. 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 future income tax decreased to $27.4 million in 2006 from $37.6 million in 2005. Included in the 2006 provision was an amount of $8.0 million recorded in the fourth quarter (2005 - $8.8 million). Our trust structure is unique and was designed to provide for discretion at the operating trust level to distribute taxable income to the Trust. Our 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, 2006 the Trust has tax pools of approximately $670.8 million (December 31, 2005 - $582.4 million) available for deduction against future income.
MARKETING
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 counter-parties for the purpose of protecting a portion of its future revenues from the volatility of oil and natural gas prices. During 2006, we recorded a hedging gain of $37.8 million as compared to a hedging loss of $39.6 million in 2005. As set out under the section "Critical Accounting Estimates", we adopted, effective January 1, 2004, the CICA Accounting Guideline 13 with respect to Hedging Relationships. 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, 2007 Fixed price 200 bbl $82.82/bbl January 1 to March 31, 2007 Fixed price 200 bbl $87.35/bbl January 1 to March 31, 2007 Fixed price 200 bbl $88.00/bbl April 1 to June 30, 2007 Fixed price 200 bbl $82.39/bbl April 1 to June 30, 2007 Fixed price 200 bbl $87.10/bbl April 1 to June 30, 2007 Fixed price 200 bbl $88.05/bbl July 1 to September 30, 2007 Fixed price 200 bbl $87.61/bbl July 1 to September 30, 2007 Fixed price 200 bbl $88.20/bbl July 1 to September 30, 2007 Fixed price 200 bbl $77.12/bbl October 1 to December 31, 2007 Fixed price 200 bbl $77.51/bbl January 1 to March 31, 2008 Fixed price 200 bbl $78.55/bbl Natural Gas Price Period Hedged Type Daily Volume (CAD) ------------------------------------------------------------------------- April 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $9.27/GJ Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $8.71/GJ Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $9.00/GJ Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $9.05/GJ Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $10.06/GJ Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $10.28/GJ Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $11.40/GJ Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $11.60/GJ Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $9.65/GJ Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $10.25/GJ Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $9.00/GJ Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $8.65/GJ Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $9.23/GJ April 1 to October 31, 2007 Fixed price 5,000 GJ $8.60/GJ April 1 to October 31, 2007 Fixed price 5,000 GJ $7.50/GJ April 1 to October 31, 2007 Fixed price 5,000 GJ $7.25/GJ April 1 to October 31, 2007 Fixed price 5,000 GJ $7.51/GJ April 1 to October 31, 2007 Fixed price 5,000 GJ $7.50/GJ April 1 to October 31, 2007 Fixed price 5,000 GJ $7.60/GJ April 1 to October 31, 2007 Fixed price 5,000 GJ $7.60/GJ April 1 to October 31, 2007 Fixed price 5,000 GJ $7.80/GJ April 1 to October 31, 2007 Fixed price 5,000 GJ $7.50/GJ April 1 to October 31, 2007 Fixed price 5,000 GJ $7.70/GJ April 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $8.90/GJ April 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $8.35/GJ
Commodity Price Sensitivity
Our low operating costs, low distribution ratio and long reserve life reduce our sensitivity to changes in commodity prices.
Currency Risk Management
The Trust is exposed to fluctuations in the Canadian/US dollar exchange ratio since our 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 our commodity hedging strategy as we hedge 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 we have not entered into any agreements to further manage this specific risk.
Interest Rate Risk Management
The Trust is exposed to interest rate risk in relation to interest expense on its revolving demand facility. Currently we have not entered into any agreements to manage this risk. At December 31, 2006, the increase or decrease in earnings for each 100 bps change in interest rate paid on the outstanding revolving demand loan amounts to approximately $3.6 million per annum.
LIQUIDITY AND CAPITAL RESOURCES
Funds from Operations
-------------------------------------------------------------------------
Three Months ended Twelve Months ended
Dec. 31 Dec. 31
($000) 2006 2005 2006 2005
-------------------------------------------------------------------------
Net earnings 47,012 60,745 195,228 161,568
Items not requiring cash:
Provision for (recovery of)
performance based compensation (10,340) (57,459) (10,149) (18,271)
Future income tax expense 7,980 8,832 27,357 37,618
Depletion, depreciation &
accretion 20,397 16,642 81,098 58,208
Non-recurring items:
Market and reserve value
performance based compensation 12,311 57,847 12,311 57,847
-------------------------------------------------------------------------
Funds from operations 77,360 86,607 305,845 296,970
-------------------------------------------------------------------------
For the quarter ended December 31, 2006, funds from operations totaled $77.4 million or $0.74 per unit, representing a 23 percent decrease from the $86.6 million, or $0.85 per unit during the same period in 2005. For fiscal 2006 funds from operations totaled $305.8 million or $2.93 per unit compared to $297.0 million or $3.01 per unit in 2005. Peyto's policy is to distribute approximately 50% of funds from operations to unitholders while retaining the balance to fund its growth oriented capital expenditures program. Our earnings and cash flow are sensitive to changes in commodity prices, exchange rates and other factors that are beyond our control. Current volatility in commodity prices creates uncertainty as to our funds from operations and capital expenditure budget. Accordingly, we assess results throughout the year and revise our operational plans as necessary to reflect the most current information.
Our 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
We have an extendible revolving term credit facility with a syndicate of financial institutions in the amount of $450 million including a $430 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 2006 was 5.0% (2005 - 4.0%).
At December 31, 2006, $420 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, 2006, we had a working capital deficit of $13.6 million.
We believe that funds generated from our operations, together with borrowings under our credit facility and proceeds from equity issued will be sufficient to finance our current operations and planned capital expenditure program. The total amount of capital we invest in 2007 will be driven by the number and quality of projects we generate. Capital will only be invested if it meets the long term objectives of the trust. The majority of our 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, 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 8, 2007. On January 8, 2007, subsequent to the issuance of these units, 105,536,584 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, 2004 47,725,272 138,953 Trust units issued by private placement 670,000 31,586 Trust unit issue costs - (103) Trust units issued pursuant to DRIP 28,645 1,356 Trust units issued pursuant to 2 for 1 split 48,423,917 - Trust units issued by public offering 5,000,000 152,750 Trust unit issue costs - (8,054) Trust units issued pursuant to DRIP 279,561 7,448 Trust units issued pursuant to OTUPP 206,452 4,800 ------------------------------------------------------------------------- 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 ------------------------------------------------------------------------- -------------------------------------------------------------------------
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 3% 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) 2006 2005 Change
-------------------------------------------------------------------------
Net present value of proved producing
reserves at 8% based on constant
Paddock Lindstrom 2007 price forecast 1,728.6 1,575.9
Net debt before performance based
compensation (426.4) (287.9)
2006 distributions - (173.8)
---------------------------------
Net value 1,302.2 1,114.2 188.0
Equity adjustment factor(x) 81%
-------------
Equity adjusted increase in value 152.3
-------------
2006 reserve value based compensation
at 3% $4.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 7% 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. A tax factor of 1.333 is then applied to determine the amount to be paid. The 2006 market based component was based on 1.5 million vested rights (all of which were granted prior to May 2004) at an average grant price of $18.77, average cumulative distributions of $3.86 and the five day weighted average closing price of $17.68. In 2006, there was a recovery of the previously recorded provision for future performance based compensation due to a reduction of trust unit market price.
The total amount expensed under these plans was as follows:
-------------------------------------------------------------------------
2006 2005
($000) $ $
-------------------------------------------------------------------------
Market based compensation 8,491 45,045
Reserve value based compensation 4,570 12,802
Recovery of prior year unpaid reserve bonus (750) -
-------------------------------------------------------------------------
Total 12,311 57,847
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the market based component, compensation costs as at December 31, 2006 related to 2.7 million non-vested rights with an average grant price of $24.78 were nil (2005 - $21.7 million).
Capital Expenditures
Net capital expenditures for the fourth quarter of 2006 totaled $28.4 million. Exploration and development related activity represented $22.8 million or 80% of the total, while expenditures on facilities, gathering systems and equipment totaled $5.0 million or 18% of the total. The following table summarizes capital expenditures for the year.
-------------------------------------------------------------------------
Three Months ended Twelve Months ended
Dec. 31 Dec. 31
($000) 2006 2005 2006 2005
-------------------------------------------------------------------------
Land - 3,657 13,253 12,324
Seismic 583 3,309 8,944 11,559
Drilling - Exploratory &
Development 22,777 84,189 227,585 274,360
Production Equipment, Facilities
& Pipelines 5,036 16,308 61,961 59,810
Acquisitions & Dispositions - - - -
Office Equipment 17 184 183 401
-------------------------------------------------------------------------
Total Capital Expenditures 28,413 107,647 311,926 358,454
-------------------------------------------------------------------------
Cash Distributions
-------------------------------------------------------------------------
Three Months ended Twelve Months ended
Dec. 31 Dec. 31
2006 2005 2006 2005
-------------------------------------------------------------------------
Funds from operations ($000) 77,360 86,607 305,845 296,970
Total distributions ($000) 44,206 36,773 173,755 136,648
Total distributions per unit ($)(x) 0.42 0.36 1.66 1.39
Payout ratio (%) 57 42 57 46
Cash distributions ($000)
(net of DRIP) 44,206 33,771 158,204 127,094
Payout ratio (%) 57 39 52 43
-------------------------------------------------------------------------
(x) Note: prior periods restated for 2 for 1 split of trust units
completed May 31, 2005.
Peyto's strategy is to distribute approximately 50 percent of funds from operations to our unitholders on a monthly basis with the balance being withheld to fund capital expenditures. The Board of Directors is prepared to adjust the payout levels to balance desired distributions with our requirement to maintain 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.
Contractual Obligations
The Trust is committed to payments under operating leases for office space as follows:
-------------------------------------------------------------------------
($000) $
-------------------------------------------------------------------------
2007 953
2008 1,097
2009 1,097
2010 1,097
2011 1,097
-------------------------------------------------------------------------
5,341
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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
During the period ended March 31, 2006, the Trust participated in a joint venture capital project with a company whose director was also a Peyto director until May 16, 2006. The Trust's participation in this joint venture amounted to $620,218. Costs associated with this joint venture capital project were billed and paid in accordance with normal business operations.
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, 2006, legal fees totaled $695,563.
INCOME TAXES
The following sets out a general discussion of the Canadian and US tax consequences of holding Peyto units as capital property. The summary is not exhaustive in nature and is not intended to provide legal or tax advice. Unitholders or potential Unitholders should consult their own legal or tax advisors as to their particular tax consequences.
Canadian Taxpayers
The Trust qualifies as a mutual fund trust under the Income Tax Act (Canada) and, accordingly, Trust units are qualified investments for RRSPs, RRIFs, RESPs and DPSPs. Each year, the Trust is required to file an income tax return and any taxable income of the Trust is allocated to unitholders.
Unitholders are required to include in computing income their pro rata share of any taxable income earned by the Trust in that year. An investor's adjusted cost base (ACB) in a trust unit equals the purchase price of the unit less any non taxable cash distributions received from the date of acquisition. To the extent the unitholders' ACB is reduced below zero, such amount will be deemed to be a capital gain to the unitholder and the unitholders' ACB will be brought to nil.
During 2006, the Trust paid distributions to the unitholders in the amount of $173.8 million (2005 - $136.7 million) in accordance with the following schedule:
Production Period Record Date Distribution Date Per Unit(x)
-------------------------------------------------------------------------
January 2006 January 31, 2006 February 15, 2006 $0.12
February 2006 February 28, 2006 March 15, 2006 $0.14
March 2006 March 31, 2006 April 13, 2006 $0.14
April 2006 April 30, 2006 May 15, 2006 $0.14
May 2006 May 31, 2006 June 15, 2006 $0.14
June 2006 June 30, 2006 July 14, 2006 $0.14
July 2006 July 31, 2006 August 15, 2006 $0.14
August 2006 August 31, 2006 September 15, 2006 $0.14
September 2006 September 30, 2006 October 13, 2006 $0.14
October 2006 October 31, 2006 November 15, 2006 $0.14
November 2006 November 30, 2006 December 15, 2006 $0.14
December 2006 December 31, 2006 January 15, 2007 $0.14
-------
$1.66
-------
-------
(x) Note: restated for 2 for 1 split of trust units completed
May 31, 2005.
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.
US unitholders are advised to seek legal or tax advice from their professional advisors.
RISK MANAGEMENT
Investors who purchase our 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.
Our 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 we receive for our 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 we receive for our 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 our focus is on internally generated drilling programs, any acquisition of oil and natural gas assets depends on our assessment of value at the time of acquisition. Incorrect assessments of value can adversely affect distributions to unitholders and the value of the units. We employ experienced staff on our team and perform appropriate levels of due diligence on our 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, we employ experienced staff to evaluate and operate wells and utilize appropriate technology in our operations. In addition, we use prudent work practices and procedures, safety programs and risk management principles, including insurance coverage against certain potential losses.
The value of our Trust units is based on among other things, the underlying value of the oil and natural gas reserves. Geological and operational risks can affect the quantity and quality of reserves and the cost of ultimately recovering those reserves. Lower oil and gas prices increase the risk of write downs on our oil and gas property investments. In order to mitigate this risk, our 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.
Our access to markets may be restricted at times by pipeline or processing capacity. We minimize these risks by controlling as much of our 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. We have no control over the level of government intervention or taxation in the petroleum and natural gas industry. However, we operate in such a manner to ensure, to the best of our knowledge that we are 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. We have reviewed our environmental risks and are, to the best of our knowledge, in compliance with the appropriate environmental legislation and have determined that there is no current material impact on our operations.
We are subject to financial market risk. In order to maintain substantial rates of growth, we must continue reinvesting in, drilling for or acquiring petroleum and natural gas. Our capital expenditure program is funded primarily through funds from operations, debt and, if appropriate, equity.
DISCLOSURE CONTROLS AND PROCEDURES
Disclosure controls and procedures have been designed to ensure that information required to be disclosed by the Trust is accumulated and communicated to the Trust's management as appropriate to allow timely decisions regarding required disclosure. The Trust's Chief Executive Officer and Chief Financial Officer have concluded, based on their evaluation as of the end of the period covered by the Trust's annual filings for the most recently completed financial year, that the Trust's disclosure controls and procedures as of the end of such period are effective to provide reasonable assurance that material information related to the Trust, including its consolidated subsidiaries, is made known to them by others within those entities.
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. During 2006, the Trust engaged external consultants to assist in documenting and assessing the Trust's design of internal controls over financial reporting. No material changes were identified in the Trust's internal control of financial reporting during the three months ended December 31, 2006, 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, 2006 were audited by independent petroleum engineers Paddock Lindstrom & Associates Ltd. Paddock has been evaluating reserves in this area and for Peyto for 8 consecutive years.
Depletion and Depreciation Estimate
We follow the full cost method of accounting for petroleum and natural gas operations 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 2007. A quarterly provision for the reserve value based compensation is calculated using estimated proved producing reserve additions adjusted for changes in debt, equity and distributions. Actual proved producing reserves additions and forecasted commodity prices could vary significantly from those estimated and may have a material effect on the calculation.
Income Taxes
The determination of the Trust's income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded.
RECENT ACCOUNTING PRONOUNCEMENTS
Comprehensive Income, Financial Instruments and Hedges
The Canadian Institute of Chartered Accountants (CICA) issued new standards in early 2005 for Comprehensive Income (CICA 1530), Financial Instruments (CICA 3855) and Hedges (CICA 3865) which will be effective for the reporting year end 2007. The new standards will bring Canadian rules in line with current rules in the US. The standards will introduce the concept of "Comprehensive Income" to Canadian GAAP and will require that an enterprise (a) classify items of comprehensive income by their nature in a financial statement and (b) display the accumulated balance of comprehensive income separately from retained earnings and additional paid-in capital in the equity section of the statement of financial position. Derivative contracts will be carried on the balance sheet at their mark-to-market value, with the change in value flowing to either net income or comprehensive income. Gains and losses on instruments that are identified as hedges will flow initially to comprehensive income and be brought into net income at the time the underlying hedged item is settled. It is expected that this standard will be effective for the Trust's 2007 reporting. Any instruments that do not qualify for hedge accounting will be marked-to-market with the adjustment (tax effected) flowing through the income statement.
Distributable Cash
The Canadian Institute of Chartered Accountants (CICA) has issued draft guidance on the calculation and disclosure of distributable cash. As well, the Canadian Securities Administrators (CSA) has proposed amendments to National Policy (NI) 41-201 - Income trusts and other indirect offerings, the most significant of which relates to distributable cash. The intent of both of these documents is to address inconsistencies and financial reporting shortcomings in the calculation and disclosure of distributable cash, improving transparency regarding the sources of distributable cash to help investors assess the sustainability of distributions. Both of these draft documents are currently out for comment. The Trust will comply with any CICA standard or CSA NI 41-201 amendment when issued in final form.
ADDITIONAL INFORMATION
Additional information relating to Peyto Energy Trust can be found on SEDAR at www.sedar.com and www.peyto.com.
Quarterly information
-------------------------------------------------------------------------
2006
Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Operations
Production
Natural gas (mcf/d) 112,296 115,304 112,484 110,878
Oil & NGLs (bbl/d) 3,834 4,205 4,145 4,143
Barrels of oil
equivalent
(boe/d at 6:1) 22,550 23,422 22,892 22,622
Average product prices
Natural gas ($/mcf) 8.84 7.81 7.96 9.26
Oil & natural gas
liquids ($/bbl) 54.89 64.50 66.94 57.12
Average operating
expenses ($/boe) 2.69 1.90 2.26 1.81
Average transportation
costs ($/boe) 0.52 0.58 0.59 0.63
Field netback ($/boe) 40.85 36.58 39.64 40.02
General & administrative
expense ($/boe) 0.85 0.55 0.43 0.06
Interest expense ($/boe) 2.72 2.52 2.00 1.36
Financial
($000 except per unit)
Revenue 110,696 107,844 106,751 113,717
Royalties (net of ARTC) 19,271 23,680 18,236 27,258
Funds from operations 77,360 72,360 77,507 78,617
Funds from operations
per unit 0.74 0.69 0.74 0.76
Total distributions 44,206 44,111 43,921 41,517
Total distributions
per unit 0.42 0.42 0.42 0.40
Payout ratio 57% 61% 57% 53%
Cash distributions
(net of DRIP) 44,206 41,019 38,315 34,665
Payout ratio 57% 57% 49% 44%
Earnings 47,012 46,155 56,768 45,293
Earnings per
diluted unit 0.44 0.44 0.54 0.44
Capital expenditures 28,413 71,223 67,195 145,094
Weighted average
trust units
outstanding 105,251,394 104,924,702 104,472,570 103,910,640
-----------------------------------------------
2005
Q4 Q3
-----------------------------------------------
Operations
Production
Natural gas (mcf/d) 108,356 108,460
Oil & NGLs (bbl/d) 4,185 4,569
Barrels of oil
equivalent
(boe/d at 6:1) 22,245 22,646
Average product prices
Natural gas ($/mcf) 10.55 8.67
Oil & natural gas
liquids ($/bbl) 58.43 57.22
Average operating
expenses ($/boe) 1.95 1.70
Average transportation
costs ($/boe) 0.70 0.66
Field netback ($/boe) 43.33 38.39
General & administrative
expense ($/boe) 0.05 0.13
Interest expense ($/boe) 0.91 1.16
Financial
($000 except per unit)
Revenue 127,633 110,566
Royalties (net of ARTC) 33,522 25,654
Funds from operations 86,607 77,179
Funds from operations
per unit 0.85 0.78
Total distributions 36,773 35,505
Total distributions
per unit 0.36 0.36
Payout ratio 42% 46%
Cash distributions
(net of DRIP) 33,771 32,318
Payout ratio 39% 42%
Earnings 60,745 37,702
Earnings per
diluted unit 0.60 0.38
Capital expenditures 107,647 93,001
Weighted average
trust units
outstanding 102,148,411 98,584,597
Peyto Energy Trust
Consolidated Balance Sheets
($000)
December 31, December 31,
2006 2005
$ $
-------------------------------------------------------------------------
Assets
Current
Cash 10,806 -
Accounts receivable 53,418 82,793
Due from private placements (Note 6) 5,042 27,450
Prepaid expenses and deposits 2,681 1,796
-------------------------------------------------------------------------
71,947 112,039
Property, plant and equipment (Note 3) 1,064,753 832,887
-------------------------------------------------------------------------
1,136,700 944,926
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities and Unitholders' Equity
Current
Accounts payable and accrued liabilities 70,836 208,394
Cash distributions payable 14,735 11,530
Provision for future performance based
compensation (Note 10) - 8,748
-------------------------------------------------------------------------
85,571 228,672
-------------------------------------------------------------------------
Long-term debt (Note 4) 420,000 180,000
Provision for future performance based
compensation (Note 10) - 1,401
Asset retirement obligations (Note 5) 5,767 4,729
Future income taxes (Note 11) 135,650 108,293
-------------------------------------------------------------------------
561,417 294,423
-------------------------------------------------------------------------
Unitholders' equity
Unitholders' capital (Note 6) 398,434 328,736
Units to be issued (Note 6) 5,042 28,332
Accumulated earnings 86,236 64,763
-------------------------------------------------------------------------
489,712 421,831
-------------------------------------------------------------------------
1,136,700 944,926
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
On behalf of the Board:
(signed) "Michael MacBean" (signed) "Darren Gee"
Director Director
Peyto Energy Trust
Consolidated Statements of Earnings and Accumulated Earnings
($000 except per unit amounts)
For the years ended December 31,
2006 2005
$ $
-------------------------------------------------------------------------
Revenue
Petroleum and natural gas sales, net 350,562 324,893
-------------------------------------------------------------------------
Expenses
Operating (Note 8) 18,046 12,546
Transportation 4,856 5,520
General and administrative(Note 9) 3,966 680
Performance based compensation (Note 10) 12,311 57,847
Future performance based compensation (Note 10) (10,149) (18,271)
Interest on long term debt 18,011 8,702
Depletion, depreciation and accretion
(Note 3 and 5) 81,098 58,208
-------------------------------------------------------------------------
128,139 125,232
-------------------------------------------------------------------------
Earnings before taxes 222,423 199,661
-------------------------------------------------------------------------
Taxes
Future income tax expense (Note 11) 27,357 37,618
Capital tax expense (162) 475
-------------------------------------------------------------------------
27,195 38,092
-------------------------------------------------------------------------
Net earnings for the year 195,228 161,568
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Accumulated earnings, beginning of year 64,763 39,843
-------------------------------------------------------------------------
Distributions (Note 7) (173,755) (136,648)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Accumulated earnings, end of year 86,236 64,763
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per unit (Note 6)
Basic 1.86 1.64
Diluted 1.86 1.64
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
Peyto Energy Trust
Consolidated Statements of Cash Flows
($000)
For the years ended December 31,
2006 2005
$ $
-------------------------------------------------------------------------
Cash provided by (used in)
Operating Activities
Net earnings for the year 195,228 161,568
Items not requiring cash:
Future performance based compensation (10,149) (18,271)
Future income tax expense 27,357 37,618
Depletion, depreciation and accretion 81,098 58,208
Change in non-cash working capital related
to operating activities (Note 13) (37,489) 35,777
-------------------------------------------------------------------------
256,045 274,900
-------------------------------------------------------------------------
Financing Activities
Issue of trust units, net of costs 30,857 181,508
Cash distributions paid (net of DRIP) (158,204) (127,094)
Increase in bank debt 240,000 -
Change in non-cash working capital related
to financing activities (Note 13) 25,613 2,092
-------------------------------------------------------------------------
138,266 56,506
-------------------------------------------------------------------------
Investing Activities
Additions to property, plant and equipment (311,926) (358,453)
Change in non-cash working capital related
to investing activities (Note 13) (71,579) 27,047
-------------------------------------------------------------------------
(383,505) (331,406)
-------------------------------------------------------------------------
Net increase (decrease) in cash 10,806 -
Cash, beginning of year - -
-------------------------------------------------------------------------
Cash, end of year 10,806 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
Peyto Energy Trust
Notes to Consolidated Financial Statements
December 31, 2006 and 2005
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 Peyto Energy Trust
and its wholly owned subsidiaries, Peyto Exploration & Development
Corp. and Peyto Operating Trust.
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 lower of cost and market
of unproved properties 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 lower of cost and market 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. The 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 not 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.
If hedge accounting were not followed, these derivative contracts
would be treated as freestanding derivative financial instruments.
Any resulting financial asset or liability would be recognized in the
balance sheet and measured at fair value, with changes in fair value
recognized currently in 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 amount 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.
The Trust is a taxable entity under the Income Tax Act (Canada) and
is taxable only on income that is not distributed or distributable to
unitholders. As the Trust distributes all of its taxable income to
unitholders and meets the requirements of the Income Tax Act (Canada)
applicable to the Trust, no provision for future income taxes in the
Trust has been made.
3. Property, Plant and Equipment
2006 2005
($000) $ $
---------------------------------------------------------------------
Property, plant and equipment 1,288,616 976,005
Accumulated depletion and depreciation (223,863) (143,118)
---------------------------------------------------------------------
1,064,753 832,887
---------------------------------------------------------------------
---------------------------------------------------------------------
At December 31, 2006 costs of $38,939,577 (December 31, 2005 -
$33,617,224) related to undeveloped land have been excluded from the
depletion and depreciation calculation.
The Trust performed a ceiling test calculation at December 31, 2006
resulting in the undiscounted cash flows from proved reserves plus
the lower of cost and market of unproved properties exceeding the
carrying value of petroleum and natural gas assets. The impairment
test was calculated at December 31, 2006 using the following
independent engineering consultant's forecasted prices:
There-
after
2007 2008 2009 2010 2011 (2)
---------------------------------------------------------------------
Edmonton Ref Price
($CDN/bbl)(1) 68.58 67.40 67.37 65.04 62.71 +2%
---------------------------------------------------------------------
AECO ($CDN/mmbtu) 7.33 7.91 7.89 7.87 8.02 +2%
---------------------------------------------------------------------
(1) Future prices incorporated a $0.87 US/CDN exchange rate.
(2) Percentage change of 2.0% represents the change in future prices
each year after 2011 to the end of the reserve life.
4. Long-Term Debt
The Trust has a syndicated $450 million extendible revolving credit
facility with a stated term date of May 7, 2007. The facility is made
up of a $20 million working capital sub-tranche and a $430 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 2006 was 5.0% (2005 - 4.0%).
5. 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 $5.8 million as at
December 31, 2006 (2005 - $4.7 million) based on a total future
liability of $23.1 million (2005 - $19.8 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:
2006 2005
($000) $ $
---------------------------------------------------------------------
Carrying amount, beginning of year 4,729 3,329
Increase in liabilities during the year 686 1,129
Settlement of liabilities during the year - -
Accretion expense 352 271
---------------------------------------------------------------------
Carrying amount, end of year 5,767 4,729
---------------------------------------------------------------------
---------------------------------------------------------------------
6. Unitholders' Capital
Authorized: Unlimited number of voting trust units
Issued and Outstanding
Trust Units (no par value) Number of Amount
($000) Shares/Units $
---------------------------------------------------------------------
Balance, December 31, 2004 47,725,272 138,953
Trust units issued by private placement 670,000 31,586
Trust unit issue costs - (103)
Trust units issued pursuant to DRIP 28,645 1,356
Trust units issued pursuant to
2 for 1 split 48,423,917 -
Trust units issued by public offering 5,000,000 152,750
Trust unit issue costs - (8,054)
Trust units issued pursuant to DRIP 279,561 7,448
Trust units issued pursuant to OTUPP 206,452 4,800
---------------------------------------------------------------------
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
---------------------------------------------------------------------
---------------------------------------------------------------------
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
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 (priced using the weighted average price for the last
5 trading days of December). These trust units were issued on
January 8, 2007. On December 31, 2005 the Trust completed a private
placement of 1,081,570 trust units to employees and consultants for
net proceeds of $27,450,247. These trust units were issued on
January 12, 2006.
Per Unit Amounts
Earnings per unit have been calculated based upon the weighted
average number of units outstanding during the year of 104,554,325
(2005 - 98,576,640). 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.
7. Accumulated Cash Distributions
Peyto's strategy is to distribute approximately 50 percent of funds
from operations to our unitholders on a monthly basis with the
balance being withheld to fund capital expenditures. The Board of
Directors is prepared to adjust the payout levels to balance desired
distributions with our requirement to maintain an appropriate capital
structure. During the year, the Trust paid distributions to the
unitholders in the aggregate amount of $173.8 million (2005 -
$136.7 million) in accordance with the following schedule:
Production Period Record Date Distribution Date Per Unit
---------------------------------------------------------------------
January 2006 January 31, 2006 February 15, 2006 $0.12
February 2006 February 28, 2006 March 15, 2006 $0.14
March 2006 March 31, 2006 April 13, 2006 $0.14
April 2006 April 30, 2006 May 15, 2006 $0.14
May 2006 May 31, 2006 June 15, 2006 $0.14
June 2006 June 30, 2006 July 14, 2006 $0.14
July 2006 July 31, 2006 August 15, 2006 $0.14
August 2006 August 31, 2006 September 15, 2006 $0.14
September 2006 September 30, 2006 October 13, 2006 $0.14
October 2006 October 31, 2006 November 15, 2006 $0.14
November 2006 November 30, 2006 December 15, 2006 $0.14
December 2006 December 31, 2006 January 15, 2007 $0.14
8. Operating Expenses
The Trust's operating expenses include all costs with respect to
day-to-day well and facility operations. Processing and gathering
income related to joint venture and third party natural gas reduces
operating expenses.
2006 2005
($000) $ $
---------------------------------------------------------------------
Field expenses 25,765 17,609
Processing and gathering income (7,719) (5,063)
---------------------------------------------------------------------
Total operating costs 18,046 12,546
---------------------------------------------------------------------
---------------------------------------------------------------------
9. General and Administrative Expenses
General and administrative expenses are reduced by operating and
capital overhead recoveries from operated properties.
2006 2005
($000) $ $
---------------------------------------------------------------------
General & Administrative expenses 9,397 6,434
Overhead recoveries (5,431) (5,754)
---------------------------------------------------------------------
Net General & Administrative expenses 3,966 680
---------------------------------------------------------------------
10. 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 3% 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) 2006 2005 Change
---------------------------------------------------------------------
Net present value of proved producing
reserves at 8% based on constant
Paddock Lindstrom 2007 price
forecast 1,728.6 1,575.9
Net debt before performance based
compensation (426.4) (287.9)
2006 distributions - (173.8)
-------------------------------
Net value 1,302.2 1,114.2 188.0
Equity adjustment factor(x) 81%
---------
Equity adjusted increase in value 152.3
---------
2006 reserve value based
compensation at 3% $4.6
---------------------------------------------------------------------
---------------------------------------------------------------------
(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 7% 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. A tax factor of 1.333 is then applied to
determine the amount to be paid. The 2006 market based component was
based on 1.5 million vested rights at an average grant price of
$18.77, average cumulative distributions of $3.86 and the five day
weighted average closing price of $17.68 (2005 - 2.0 million rights,
average grant price of $10.82, average cumulative distributions of
$2.18 per unit and five day weighted average closing price of
$25.38). In 2006, there was a recovery of the previously recorded
provision for future performance based compensation due to a
reduction of trust unit market price.
The total amount expensed under these plans was as follows:
2006 2005
($000) $ $
---------------------------------------------------------------------
Market based compensation 8,491 45,045
Reserve value based compensation 4,570 12,802
Recovery of prior year unpaid reserve bonus (750) -
---------------------------------------------------------------------
Total 12,311 57,847
---------------------------------------------------------------------
---------------------------------------------------------------------
For the market based component, compensation costs as at December 31,
2006 related to 2.7 million non-vested rights with an average grant
price of $24.78 were nil (2005 - $21.7 million).
11. Future Income Taxes
2006 2005
($000) $ $
---------------------------------------------------------------------
Earnings before income taxes 222,423 199,661
Statutory income tax rate 36.75% 37.62%
---------------------------------------------------------------------
Expected income taxes 81,740 75,112
Increase (decrease) in income taxes from:
Non-deductible crown charges 10,328 24,372
Resource allowance (11,812) (21,706)
Corporate income tax rate change (2,397) (371)
Attributed Canadian Royalty Income (ACRI) - (1,023)
Income attributed to the trust (50,823) (38,424)
Change in valuation allowance for share
issue costs 1,000 (994)
Other (679) 651
---------------------------------------------------------------------
Future income tax expense 27,357 37,618
---------------------------------------------------------------------
---------------------------------------------------------------------
The net future income tax liability is comprised of:
2006 2005
$ $
---------------------------------------------------------------------
Differences between tax base and reported
amounts for depreciable assets 137,322 112,789
Accrued expenditures - (2,859)
Provision for asset retirement obligation (1,672) (1,637)
---------------------------------------------------------------------
135,650 108,293
---------------------------------------------------------------------
---------------------------------------------------------------------
At December 31, 2006 the Trust has tax pools of approximately
$670.8 million (December 31, 2005 - $582.4 million) available for
deduction against future income. Peyto Energy Trust has approximately
$7.7 million in unrecognized future income tax assets available to
reduce future taxable income.
Proposed Tax Legislation
On October 31, 2006, the Minister of Finance announced its proposal
to amend the Income Tax Act (Canada) to apply a Distribution Tax on
distributions from publicly-traded income trusts. Under the proposal,
existing income trusts will be subject to the new measures commencing
in their 2011 taxation year, following a four-year grace period. The
Minister of Finance has issued a Notice of Ways and Means Motion to
Amend the Income Tax Act, but it is not known at this time if or when
the proposal will be enacted by Parliament. In simplified terms,
under the proposed tax plan, income distributions will first be taxed
at the trust level at a special rate estimated to be 31.5%. Income
distributions to individual unitholders will then be treated as
dividends from a Canadian corporation and eligible for the dividend
tax credit. Income distributions to corporations resident in Canada
will be eligible for full deduction as tax free intercorporate
dividends. Tax-deferred accounts (RRSPs, RRIFs and Pension Plans)
will continue to pay no tax on distributions. Non-resident
unitholders will be taxed on distributions at the non-resident
withholding tax rate for dividends. The net impact on Canadian
taxable investors is expected to be minimal because they can take
advantage of the dividend tax credit. However, as a result of the
31.5% Distribution Tax at the trust level, distributions to
tax-deferred accounts will be reduced by approximately 31.5%, and
distributions to non-residents will be reduced by approximately
26.5%.
12. Financial Instruments
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, 2006 is as follows:
Weighted
Crude Oil Daily Average
Period Hedged Type Volume Price (CAD)
---------------------------------------------------------------------
January 1 to March 31, 2007 Fixed price 200 bbl $82.82/bbl
January 1 to March 31, 2007 Fixed price 200 bbl $87.35/bbl
January 1 to March 31, 2007 Fixed price 200 bbl $88.00/bbl
April 1 to June 30, 2007 Fixed price 200 bbl $82.39/bbl
April 1 to June 30, 2007 Fixed price 200 bbl $87.10/bbl
April 1 to June 30, 2007 Fixed price 200 bbl $88.05/bbl
July 1 to September 30, 2007 Fixed price 200 bbl $87.61/bbl
July 1 to September 30, 2007 Fixed price 200 bbl $88.20/bbl
Weighted
Natural Gas Daily Average
Period Hedged Type Volume Price (CAD)
---------------------------------------------------------------------
April 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $9.27/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $8.71/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $9.00/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $9.05/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $10.06/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $10.28/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $11.40/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $11.60/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $9.65/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $10.25/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $9.00/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $8.65/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $9.23/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $8.60/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $7.50/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $7.25/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $7.51/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $7.50/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $7.60/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $7.60/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $7.80/GJ
April 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $8.90/GJ
As at December 31, 2006, the Trust had committed to the future sale
of 145,400 barrels of crude oil at an average price of $86.45 per
barrel and 16,235,000 gigajoules (GJ) of natural gas at an average
price of $8.54 per GJ or $9.99 per mcf based on the historical
heating value of Peyto's natural gas. These contracts will generate
revenue totaling $151.2 million. Based on the market's estimate of
the future commodity prices as at December 31, 2006 the fair value of
these contracts would be $117.3 million. Had these contracts been
closed on December 31, 2006, the Trust would have realized a gain in
the amount of $33.9 million.
Subsequent to December 31, 2006 the Trust entered into the following
contracts:
Natural Gas Daily Price
Period Hedged Type Volume (CAD)
---------------------------------------------------------------------
April 1 to October 31, 2007 Fixed price 5,000 GJ $7.50/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $7.70/GJ
April 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $8.35/GJ
Weighted
Crude Oil Daily Average
Period Hedged Type Volume Price (CAD)
---------------------------------------------------------------------
July 1 to September 30, 2007 Fixed price 200 bbl $77.12/bbl
October 1 to December 31, 2007 Fixed price 200 bbl $77.51/bbl
January 1 to March 31, 2008 Fixed price 200 bbl $78.55/bbl
Fair Values of Financial Assets and Liabilities
The Trust's financial instruments include cash, accounts receivable,
due from private placement deposits, current liabilities, provision
for future market performance based compensation and long term debt.
At December 31, 2006, the carrying value of cash, accounts
receivable, due from private placement deposits, current liabilities
and provision for future market 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, 2006, approximately 41% was due from one company
(December 31, 2005 - 42%). Of the Trust's revenue for the year ended
December 31, 2006, approximately 59% was received from two companies
(December 31, 2005 - 62%).
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.
13. Supplemental Cash Flow Information
Changes in non-cash working capital balances
2006 2005
($000) $ $
---------------------------------------------------------------------
Accounts receivable 29,376 (23,801)
Due from private placement 22,408 (370)
Prepaid expenses and deposits (886) 3,467
Accounts payable and accrued liabilities (137,448) 83,531
Capital taxes payable (110) (373)
Cash distributions payable 3,205 2,462
---------------------------------------------------------------------
(83,455) 64,916
Attributable to financing activities 25,613 2,092
Attributable to investing activities (71,579) 27,047
---------------------------------------------------------------------
Attributable to operating activities (37,489) 35,777
---------------------------------------------------------------------
---------------------------------------------------------------------
2006 2005
$ $
---------------------------------------------------------------------
Cash interest paid during the year 18,011 8,702
Cash taxes paid during the year - 848
---------------------------------------------------------------------
---------------------------------------------------------------------
14. 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 CNR 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 Peyto's financial position or
results of operations.
b) Commitments
The Trust is committed to payments under operating leases for office
space as follows:
($000) $
---------------------------------------------------------------------
2007 953
2008 1,097
2009 1,097
2010 1,097
2011 1,097
---------------------------------------------------------------------
5,341
---------------------------------------------------------------------
---------------------------------------------------------------------
15. Related Party Transactions
During the period ended March 31, 2006, the Trust participated in a
joint venture capital project with a company whose director was also
a Peyto director until May 16, 2006. The Trust's participation in
this joint venture amounted to $620,218. Costs associated with this
joint venture capital project were billed and paid in accordance with
normal business operations.
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, 2006, legal fees
totaled $695,563 (2005 - $522,529).
Peyto Exploration & Development Corp. Information
Officers
Darren Gee Glenn Booth
President and Chief Executive Officer Vice President, Land
Scott Robinson Kathy Turgeon
Executive Vice President and Chief Vice President, Finance
Operating Officer
Ken Veres Stephen Chetner
Vice-President, Exploration Corporate Secretary
Directors
Ian Mottershead, Chairman
Rick Braund
Don Gray
Brian Davis
John Boyd
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
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