SYMBOL: PEY.UN - TSX
CALGARY, March 8 /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 and our ability to profitably
find and develop new oil and natural gas reserves. We are proud to present our
operating and financial results for the fourth quarter and 2005 fiscal year.
The following summarizes certain of the Trust's attributes at year end.
- Long reserve life - Proved 13.6 years, Proved Plus Probable 18.9 years
- High netback $37.83/boe
- Low operating costs $1.55/boe
- Low base general and administrative costs $0.08/boe
- High operatorship - over 95% of production
- Low cash distribution ratio 42% of fourth quarter 2005 funds from
operations
- Low debt to funds from operations ratio - 0.83 (net debt, before
provision for future performance based compensation, divided by
annualized fourth quarter 2005 funds from operations)
- Distribution growth - distributions have been increased 5 times and are
now 87% higher than when the trust was formed two 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 $358 million in capital and created $995
million of Proved and $1,159 million worth of Proved Plus Probable
undiscounted reserve value
- Reserve life growth - the reserve life for every reserve category grew
by over 10% from year over year
- Asset value growth per unit(1) - the net present value of the trust's
proven producing oil and gas assets, discounted at 0%, 5% and 8%, all
grew by approximately 54% per trust unit
- NPV Recycle ratio Proved 2.8, Proved Plus Probable 3.2 (before change
in future development capital)
- Distributions per unit(1) - increased by 36% from $1.02 in 2004 to
$1.39 in 2005.
- Reserve growth per unit(1) the most conservative category, proved
producing reserves, grew 15% year over year
- Production growth - annual production increased 19% from 18,689 boe/d
in 2004 to 22,219 boe/d in 2005
- Production growth per unit(1) - increased 10% year over year
- Funds from operations growth per unit(1) - increased 42% year over year
- Cost of new reserves (FD&A) - Proved $13.33/boe, Proved Plus Probable
$11.18/boe (before change in future development capital)
- Recycle ratio Proved 3.2, Proved Plus Probable 3.8 (before change in
future development capital)
- Reserve replacement ratio Proved 3.3, Proved Plus Probable 4.0
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 $25.39 for 2005 and $23.92 for
2004.
<<
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3 Months Ended 12 Months Ended
Dec. 31 % Dec. 31 %
2005 2004 Change 2005 2004 Change
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Operations
Production
Natural gas
(mcf/d) 108,356 97,968 11% 106,701 88,842 20%
Oil & NGLs
(bbl/d) 4,185 4,360 (4)% 4,436 3,882 14%
Barrels of
oil equiv-
alent (boe/d
(at) 6:1) 22,245 20,688 8% 22,219 18,689 19%
Product prices
Natural gas
($/mcf) 10.55 7.58 39% 8.78 7.38 19%
Oil & NGLs
($/bbl) 58.43 46.82 25% 55.48 42.66 30%
Operating
expenses
($/boe) 1.95 1.03 89% 1.55 1.05 48%
Transportation
($/boe) 0.70 0.77 (9)% 0.68 0.70 (3)%
Field netback
($/boe) 43.33 32.90 32% 37.83 31.79 19%
General &
administrative
expenses
($/boe) 0.05 0.01 400% 0.08 0.12 (33)%
Interest expense
($/boe) 0.91 1.03 (12)% 1.07 1.01 6%
Financial ($000,
except per
unit)
Revenue 127,633 87,127 46% 431,695 300,501 44%
Royalties
(net of ARTC) 33,522 21,103 59% 106,802 71,089 50%
Funds from
operations 86,607 60,334 43% 296,970 209,106 42%
Funds from
operations
per unit(x) 0.85 0.65 31% 3.01 2.28 32%
Cash
distributions 36,773 26,443 39% 136,648 93,660 46%
Cash
distributions
per unit(x) 0.36 0.285 26% 1.39 1.02 36%
Percentage of
funds from
operations
distributed 42 44 (5)% 46 45 2%
Earnings 60,745 (2,558) - 161,568 73,782 119%
Earnings per
diluted unit(x) 0.60 (0.03) - 1.64 0.805 104%
Capital
expenditures 107,647 76,953 40% 358,454 230,774 55%
Weighted
average trust
units outstan-
ding(x) 102,148,411 92,494,022 10% 98,576,640 91,711,034 7%
As at
December 31
Net debt
(before future
compensation
expense) 287,885 222,969 29%
Unitholders'
equity 421,831 205,849 105%
Total assets 944,927 622,577 52%
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(x) Note: prior periods restated for 2 for 1 split of trust units
completed May 31, 2005.
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12 Months Ended Dec. 31
2005 2004
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Net Earnings 161,568 73,782
Items not requiring cash:
Non-cash provision for (recovery of)
performance based compensation (18,271) 15,945
Future income tax expense 37,618 25,558
Depletion, depreciation and accretion 58,208 40,880
Non-recurring items:
Performance based compensation 57,847 52,941
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Funds from operations(1) 296,970 209,106
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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.
Capital Expenditures
Net capital expenditures for 2005 totaled $358 million which was an
increase of 55% from 2004. In 2005, 100% of the capital was invested to
develop and produce new oil and gas reserves. The majority of our capital was
spent to drill, case, complete and bring on production from new wells in the
Deep Basin area. Capital was also spent to build 25 mmcf/d of gas processing
capacity in the Cutbank and Kakwa areas. At Sundance, where we own and operate
a 110 mmcf/d gas plant, we added additional facilities in order to minimize
future downtime due to routine maintenance. Capital invested in new land and
seismic evaluation increased from the previous year by 145%. The majority of
the value associated with this land and seismic capital will be captured in
future years when wells are drilled and reserves are produced. None of our
2005 capital was spent on acquisitions. The following table summarizes capital
expenditures for the year.
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2005 2004 Since Inception
Capital % of % of % of
Expenditures ($000) Total ($000) Total ($000) Total
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Land 12,324 3% 3,975 2% 27,713 2%
Seismic 11,559 3% 5,768 2% 24,313 3%
Drilling &
Completion -
Exploratory &
Development 274,360 77% 167,742 73% 701,943 72%
Production
Equipment,
Facilities &
Pipelines 59,810 17% 49,898 22% 186,234 19%
Acquisitions &
Dispositions - - 3,307 1% 30,856 4%
Office Equipment 401 - 84 - 857 -
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Total 358,454 100% 230,774 100% 971,916 100%
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During the year, we drilled or re-entered 120 gross (99 net) wells with a
100% success rate. The average depth of our wells was approximately 2,560m,
which is 110m deeper than the year before. Of the wells drilled during 2005,
over 77% were drilled to a depth deeper than our conventional Sundance Cardium
well depth of 2,300m. We continue to evolve the mix of our drilling prospects
to include deeper Cretaceous objective zones with the same reservoir
characteristics as our original Cardium targets. Most of our wells have at
least two and sometimes three prospective gas bearing zones for development.
The following table summarizes the well activity for 2005.
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Tied In/Brought
Well Activity Drilled Completed On Production
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Area Gross Net Gross Net Gross Net
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Sundance 90 75 98 79 86 68
Kakwa 12 11 12 10 11 9
Cutbank 9 8 12 12 14 14
Berland 4 4 3 3 4 4
Other 5 1 1 0 0 0
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Total 120 99 126 104 115 95
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Since inception, we have invested a total of $972 million in capital. We
have built a long life low cost natural gas business by investing
significantly less value than we have created. Our strategy of building our
own assets has allowed us to generate a three year compounded annual rate of
return of 70% for our unitholders. Our drill bit approach takes raw material
and turns it into a finished product. We have not had to dilute quality or
sacrifice returns by acquiring marginal production and reserves. 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 started seven years
ago.
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Funding Sources for Capital Since Inception
(from 1998 to 2005) ($000) % of Total
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Cash flow from projects found and developed
by Peyto 598,126 62%
Net Equity (Equity issued of $357.1 million less
Accumulated Distributions of $271.2 million) 85,905 9%
Net Debt (year end 2005 excluding future
performance based compensation) 287,885 29%
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Total Capital Expenditures 971,916 100%
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Reserves
During 2005, the trust was again successful in adding high quality, long
life reserves through the drill bit. The following table illustrates the
change in reserve volumes and net present value of future cash flow,
discounted at 5%, before income tax using variable pricing.
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As at December 31
% Change
Debt
Adjusted
2005 2004 % Change Per Unit
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Reserves
BOE 6:1 (mstb)
Proved Producing 87,881 70,996 24% 15%
Total Proved 110,802 92,028 20% 12%
Proved + Probable Additional 153,448 129,506 18% 10%
Net Present Value ($million)
Discounted at 5%
Proved Producing 2,113 1,281 65% 53%
Total Proved 2,539 1,533 66% 54%
Proved + Probable Additional 3,219 1,983 62% 51%
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Note: Based on the Paddock Lindstrom & Associates report effective
December 31, 2005. 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, 2006
announcing 2005 Year End Reserve Report and Distribution Increase
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 2006.
Value Creation
In order to measure investment success, it is necessary to quantify the
amount of value created during the year and compare that to the amount of
capital invested. We undertake this exercise to ensure the best 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 NPV
with this years 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. We were able to
create $995 million of Proved and $1,159 million of Proved Plus Probable
undiscounted reserve value with $358 million in capital. Relative to our
enterprise value, this amount of net value created represents a significant
growth rate.
The following table isolates value created by Peyto with the drill bit
from the increase in value due to higher commodity prices for both the total
proved and proved plus probable cases.
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Before Tax Debt Adjusted NPV Reconciliation Table ($million)
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Proved + Probable
Total Proved Additional
Discounted at Discounted at
Evaluation Formula 0% 5% 0% 5%
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NPV at Dec 31, 2004 after
net debt (Jan 1, 2005
price forecast) A $ 2,397 $ 1,288 $ 3,432 $ 1,738
NPV after net debt at
Dec 31, 2004 (Jan 1, 2006
price forecast) B $ 3,387 $ 1,884 $ 4,857 $ 2,546
NPV at Dec 31, 2005 after
net debt (Jan 1, 2006
price forecast) C $ 4,075 $ 2,242 $ 5,709 $ 2,922
2005 Funds from operations D $ 307 $ 307 $ 307 $ 307
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Increase in 2004 NPV due
to price forecast B - A $ 990 $ 596 $ 1,425 $ 808
NPV created by drill
bit in 2005 C - B + D $ 995 $ 665 $ 1,159 $ 683
Total change in debt
adjusted NPV from
2004 to 2005 C - A $ 1,678 $ 954 $ 2,277 $ 1,184
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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. These measures, such as capital cost per flowing boe, FD&A, recycle
ratio and reserve replacement ratio are incomplete and on there own do not
measure success. However, the NPV recycle ratio does measure the value of what
was created relative to what was invested. 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 2005 our proven plus probable NPV recycle ratio
was 3.2 times. This means for each dollar we invested we were able to create
3.2 new dollars of proven plus probable reserve value.
Our reserves grew faster than our production in 2005. This resulted in an
increase of over 10% in reserve life for all of the reserve categories. Our
proven plus probable reserve life grew from 17.1 years at the end of 2004 to
18.9 years at the end of 2005. For an energy trust, more money in the "reserve
bank" ultimately means more cash distributions for the unitholders.
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Proved Total Proved +
2005 Performance Ratios Developed Proved Probable
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Reserve life index (years)
Q4 2005 average production -
22,245 boe/d 11.5 13.6 18.9
Finding, development and
acquisition costs ($/boe)
Before change in future
development capital $14.45 $13.33 $11.18
Including change in future
development capital $13.88 $15.32 $15.17
Reserve replacement ratio 3.1 3.3 4.0
Recycle ratio
Before change in future
development capital 3.0 3.2 3.8
Including change in future
development capital 3.1 2.8 2.8
NPV Recycle ratio 2.6 2.8 3.2
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- Reserve life index can be calculated using various methodologies. We
believe the most accurate way to look at the reserve life index is by
dividing the proved developed reserves by the actual fourth quarter
average production. In our opinion, for comparative purposes the proved
developed reserve life will provide 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. Prior to NI 51-101, FD&A costs were calculated
excluding future development capital ("FDC"). Both methods of
calculating FD&A costs have been provided in order to facilitate
comparisons with previous years.
- Reserve replacement ratio is calculated by dividing the yearly change
in reserves, including revisions and before production by the actual
annual production.
- Recycle ratio is calculated by dividing the field net back per boe,
before hedging, by the FD&A costs for the period. 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.
- 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. The NPV recycle ratio measures the value of the
added reserves relative to their cost.
Quarterly Review
Daily production for the three months averaged 108 mmcf of natural gas
and 4,185 barrels of oil and natural gas liquids. Gains in production and
commodity prices increased funds from operations from $60.3 million in 2004 to
$86.6 million in 2005. Peyto's commodity prices net of hedging increased by
39% averaging $10.55 per mcf of natural gas, and increased by 25% averaging
$58.43 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 $1.95/boe in the fourth quarter of 2005 compared
to $1.03/boe for the fourth quarter of 2004. The fixed cost structure
associated with these wells combined with a general inflationary effect of
over 20% in the service sector caused the increase. 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 $107.6 million with drilling
projects continuing at record levels. Well related activity made up 93% of
this capital with drilling and completion costs accounting for $84.2 million
while facilities and tie-ins accounted for $16.3 million. Peyto spent a record
$3.7 million on land in the quarter in a very competitive market.
Activity Update
To date in 2006, Peyto has drilled and cased 25 gross (20 net) gas wells
and brought on-stream 19 gross (18 net) producing zones. We currently have 8
drilling rigs active in our core areas. As expected, production has remained
stable at 22,300 boe/d. In the greater Sundance area we have been limited by
processing capacity since the beginning of the third quarter of 2005. Drilled
and completed reserves are awaiting the March, 2006 completion of our Wildhay
Plant. Peyto's fourth 100% owned and operated gas plant will have 20 mmcf/d
gas processing capacity and has begun selling gas as we go to press. To the
east of Sundance, in the Nose Hill area, Peyto will be constructing a 20
mmcf/d gas plant which is expected to be on-stream by the third quarter of
2006. Both of these gas plants are easily expandable for future production
increases.
Marketing
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. 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. Our hedging approach is based on a forward
average price typically made up of fifteen to twenty transactions entered into
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 $12.60/mcf during the
fourth quarter of 2005, an increase of 74% from $7.23/mcf reported for the
equivalent period in 2004. Oil and natural gas liquids prices averaged
$63.27/bbl up 23% from $51.57/bbl a year earlier. Hedging activity for the
fourth quarter of 2005 reduced Peyto's price achieved by $10.93/boe. The
fourth quarter hedging loss was $22.4 million, for a year to date total loss
of $39.6 million. The following table shows commodity prices and revenue
before and after hedging.
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Commodity Prices Three Months ended Twelve Months ended
Dec. 31 Dec. 31
2005 2004 2005 2004
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Natural gas ($/mcf) 12.60 7.23 9.62 7.19
Hedging - gas ($/mcf) (2.05) 0.35 (0.84) 0.19
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Natural gas - after
hedging ($/mcf) 10.55 7.58 8.78 7.38
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Oil and natural gas liquids ($/bbl) 63.27 51.57 59.62 45.92
Hedging - oil ($/bbl) (4.84) (4.75) (4.14) (3.26)
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Oil and natural gas liquids -
after hedging ($/bbl) 58.43 46.82 55.48 42.66
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Total Hedging ($/boe) (10.93) 0.69 (4.88) 0.25
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Revenue Three Months ended Twelve Months ended
Dec. 31 Dec. 31
($000) 2005 2004 2005 2004
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Natural gas 125,651 65,126 374,750 233,555
Oil and natural gas liquids 24,359 20,684 96,532 65,237
Hedging gain (loss) (22,377) 1,317 (39,587) 1,709
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Total revenue 127,633 87,127 431,695 300,501
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As at December 31, 2005, Peyto had committed to the forward sale of
355,100 barrels of crude oil at an average price of $68.19 per barrel and 22.7
million gigajoules (GJ) of natural gas at an average price of $8.64 per GJ.
This presold volume for 2006 represents 60% of our current gas production net
of royalties and 33% of our current liquids production net of royalties. Based
on the historical heating value of Peyto's natural gas, the price per mcf on
the forward sale will be $10.11, which is 15% higher than the price Peyto
realized in 2005.
Performance Based Compensation
When Peyto converted to a trust in July, 2003, a formal 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 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 2005 was $57.8 million
(market component - $45 million; reserve value component - $12.8 million).
Growth in the share price in the prior two years accounted for 82% of the
total market performance based compensation paid in 2005. Total performance
based compensation paid by the trust in its first 30 months represents 7% of
the total return that unitholders have realized in the market since conversion
to a trust.
After the performance based compensation payments, two private placements
totaling 1,393,940 trust units were completed to Peyto employees and
consultants for proceeds of $34.4 million. Unlike a typical option plan, the
employees of Peyto have 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. In order for our distributions to be more sustainable and grow,
we have to profitably find and develop more reserves. Simply increasing
production from our existing reserves will not make us more sustainable. This
year we were successful in growing our reserves and improving our
sustainability. The results set out herein, continue to prove that our unique
model is working. Growth on a per unit basis has allowed us to increase our
distributions five times, or by 87% on aggregate, since the conversion to a
trust in July 2003. We have now distributed out a total of $271.2 million or
$2.855 per unit (adjusted for 2 for 1 split) to our unitholders. Since
converting to a trust, we have returned 37% of the unit price at time of
conversion, while increasing the reserves per unit by over 102% and the
production per unit by 54%.
Effective with the February 2006 production month, cash distributions
were increased by 17 percent to $0.14 per unit per month. This latest increase
in distribution is a direct result of the growth in reserves and assets of the
trust.
On March 2, 2005, Peyto implemented a Distribution Reinvestment Plan
("DRIP"). The DRIP provides a convenient mechanism for unitholders to reinvest
their monthly cash distributions in additional trust units. The DRIP permits
the purchase of Peyto trust units from treasury 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") component which provides
unitholders enrolled in the DRIP with the opportunity to purchase additional
trust units from treasury using the same pricing as the DRIP. Peyto will issue
trust units from treasury, subject to certain limitations, at the 5% discount
to satisfy the requirements of the DRIP/OTUPP, until it discloses otherwise.
The DRIP/OTUPP is currently only available to Canadian resident unitholders.
Residents of the United States may not participate in the DRIP/OTUPP Plan, as
Peyto is not a registrant with the United States Securities and Exchange
Commission. Details of the DRIP/OTUPP are available on Peyto's website
www.peyto.com.
Outlook
Every year since Peyto started our capital expenditures have grown. We
expect that this will again be the case in 2006. This growth in capital
expenditures is a direct reflection of the ability of Peyto's technical team
to build our own assets. The total amount of capital we ultimately invest in
2006 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. During the year, Peyto will be constructing
two new gas plants to ensure that we can efficiently access the new reserves
we are finding. Capital expenditures will continue to be funded with a
combination of funds from operations, working capital, equity and bank lines.
We have now completed our seventh year as an energy business. It is
amazing how far Peyto has come with our simple strategy of putting value
first. Our business has delivered returns and assets which lead the Canadian
energy sector. 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 2005 results on Thursday, March 9, 2006
at 9:00 a.m. Mountain Standard Time (MST), 11:00 a.m. Eastern Standard Time
(EST). To participate, please call 1-416-850-1243 (Toronto area) or
1-800-814-4860 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 21115481 followed by the pound key. The
replay will be available at 11:00 a.m. MST, 1:00 p.m. EST Thursday, March 9,
2006 until midnight EST on Thursday, March 16, 2006. The conference call can
also be accessed through the internet at
http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID(equal sign)1038620 for
the English version or
http://www.cnw.ca/fr/webcast/viewEvent.cgi?eventID(equal sign)1038620 for the
French version. 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
2:30p.m. on Tuesday, May 16, 2006 at the Sheraton Suites Calgary Eau Claire,
255 Barclay Parade Avenue SW, Calgary, Alberta.
Don T. Gray
President and Chief Executive Officer
March 8, 2006
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, 2005 and 2004. 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. As such,
comparative figures for the periods prior to July 1, 2003 are the financial
results of PEDC. 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 8, 2006. 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).
Recently, proposed new legislation to restrict foreign ownership was
issued in draft form by the Department of Finance and has prompted all trusts,
including Peyto, to review their capital structures. To the best of our
knowledge, Peyto's foreign ownership level currently stands at approximately
26.3 percent, well below the level that would jeopardize Peyto's status as a
mutual fund trust under this proposed legislation. A few trusts have
reorganized, or propose to reorganize, their units into a dual class structure
with the objective of restricting foreign ownership to less than 50 percent
and therefore retaining their status as a mutual fund trust. Peyto is an
active supporter of the efforts of the Canadian Association of Income Funds
(CAIF) which is attempting to have the Department of Finance reconsider
components of the proposed legislation. The Department of Finance has
subsequently announced that they are taking more time to consider the proposed
legislation. The Trust will continue to monitor these developments and if it
is deemed appropriate, propose an amendment to its capital structure.
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, 2005, we
had total proved plus probable reserves of 153.4 million barrels of oil
equivalent with a reserve life of 18.9 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 to deliver growth in its assets, production
and income, all on a per unit basis. The model is built around three key
principles:
- Using our technical expertise to achieve the best return on
capital employed, through the development of internally generated
drilling projects.
- A low payout ratio designed to efficiently fund our growing
inventory of drilling projects.
- Having an asset base which is made up of high quality long life
natural gas reserves.
Operating results over the last seven 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 2005 2004 2003
($000 except per unit amounts)
-------------------------------------------------------------------------
Total revenue (before royalties) 431,695 300,501 216,931
Funds from operations 296,970 209,106 151,407
Per unit - basic(x) 3.01 2.28 1.705
Per unit - diluted(x) 3.01 2.28 1.705
Earnings (loss) 161,568 73,782 48,579
Per unit - basic(x) 1.64 0.805 0.545
Per unit - diluted(x) 1.64 0.805 0.545
Total assets 944,927 622,577 416,146
Total long-term debt 180,000 180,000 150,000
Cash distributions per unit(x) 1.39 1.02 0.45
-------------------------------------------------------------------------
(x) Note: prior periods restated for 2 for 1 split of trust units
completed May 31, 2005.
QUARTERLY FINANCIAL INFORMATION
-------------------------------------------------------------------------
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
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2004
($000 except per unit amounts) Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Total revenue (net of royalties) 66,024 59,337 53,853 50,197
Funds from operations 60,334 54,211 48,548 46,012
Per unit - basic(x) 0.65 0.60 0.53 0.51
Per unit - diluted(x) 0.65 0.60 0.53 0.51
Earnings (loss) (2,558) 21,650 30,347 24,343
Per unit - basic(x) (0.03) 0.24 0.33 0.27
Per unit - diluted(x) (0.03) 0.24 0.33 0.27
-------------------------------------------------------------------------
(x) Note: prior periods restated for 2 for 1 split of trust units
completed May 31, 2005.
RESULTS OF OPERATIONS
Production
-------------------------------------------------------------------------
Three Months ended Twelve Months ended
Dec. 31 Dec. 31
2005 2004 2005 2004
-------------------------------------------------------------------------
Natural gas (mmcf/d) 108,356 97,968 106,701 88,842
Oil & natural gas liquids (bbl/d) 4,185 4,360 4,436 3,882
Barrels of oil equivalent (boe/d) 22,245 20,688 22,219 18,689
-------------------------------------------------------------------------
Natural gas production averaged 108.4 mmcf/d in the fourth quarter of
2005, 11 percent higher than the 97.9 mmcf/d reported for the same period in
2004. Oil and natural gas liquids production averaged 4,185 bbl/d, a decrease
of 4 percent from 4,360 bbl/d reported in the prior year. Production for the
year increased 19 percent from 18,689 boe/d to 22,219 boe/d. The production
increases are directly attributable to Peyto's ongoing drilling program.
Commodity Prices
-------------------------------------------------------------------------
Three Months ended Twelve Months ended
Dec. 31 Dec. 31
2005 2004 2005 2004
-------------------------------------------------------------------------
Natural gas ($/mcf) 12.60 7.23 9.62 7.19
Hedging - gas ($/mcf) (2.05) 0.35 (0.84) 0.19
-------------------------------------------------------------------------
Natural gas - after hedging
($/mcf) 10.55 7.58 8.78 7.38
-------------------------------------------------------------------------
Oil and natural gas liquids($/bbl) 63.27 51.57 59.62 45.92
Hedging - oil ($/bbl) (4.84) (4.75) (4.14) (3.26)
-------------------------------------------------------------------------
Oil and natural gas liquids -
after hedging ($/bbl) 58.43 46.82 55.48 42.66
-------------------------------------------------------------------------
Total Hedging ($/boe) (10.93) 0.69 (4.88) 0.25
-------------------------------------------------------------------------
Our natural gas price before hedging averaged $12.60/mcf during the
fourth quarter of 2005, an increase of 74 percent from $7.23/mcf reported for
the equivalent period in 2004. Oil and natural gas liquids prices averaged
$63.27/bbl up 23 percent from $51.57/bbl a year earlier. Natural gas prices
for the year were up 34 percent at $9.62/mcf while oil and natural gas liquids
prices were up 30 percent at $59.62/bbl compared to 2004. Hedging activity for
fiscal 2005 decreased Peyto's price achieved by $4.88/boe. Expectations are
for commodity prices to remain strong.
Revenue
-------------------------------------------------------------------------
Three Months ended Twelve Months ended
Dec. 31 Dec. 31
($000) 2005 2004 2005 2004
-------------------------------------------------------------------------
Natural gas 125,651 65,126 374,750 233,555
Oil and natural gas liquids 24,359 20,684 96,532 65,237
Hedging gain (loss) (22,377) 1,317 (39,587) 1,709
-------------------------------------------------------------------------
Total revenue 127,633 87,127 431,695 300,501
-------------------------------------------------------------------------
For the three months ended December 31, 2005, revenue increased
46 percent to $127.6 million from $87.1 million for the same period in 2004.
Revenue for the year was up 44 percent as a result of increased production
volumes and commodity prices as detailed in the following table:
-------------------------------------------------------------------------
Three Months ended Dec. 31 Twelve Months ended Dec. 31
2005 2004 Change $million 2005 2004 Change $million
-------------------------------------------------------------------------
Natural gas
Volume
(mcf/d) 108,356 97,968 10,388 106,701 88,842 17,859
Volume (mmcf) 9,969 9,013 956 7.2 38,946 32,516 6,430 47.5
Price ($/mcf) 10.55 7.58 2.97 29.6 8.78 7.38 1.40 54.5
Oil & NGL
Volume (bbl/d) 4,185 4,360 (175) 4,436 3,882 554
Volume (mbbl) 385 401 (16) (0.7) 1,619 1,421 198 8.4
Price ($/bbl) 58.43 46.82 11.61 4.4 55.48 42.66 12.82 20.8
-------------------------------------------------------------------------
Total revenue
($million) 127.6 87.1 40.5 40.5 431.7 300.5 131.2 131.2
-------------------------------------------------------------------------
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
2005 2004 2005 2004
-------------------------------------------------------------------------
Royalties, net of ARTC ($000) 33,522 21,103 106,802 71,089
% of sales 26 24 25 24
$/boe 16.38 11.08 13.17 10.39
-------------------------------------------------------------------------
For the fourth quarter of 2005, royalties averaged $16.38/boe or
approximately 26 percent of Peyto's total petroleum and natural gas sales.
Year to date royalties were 25 percent of sales in 2005 compared to 24 percent
in 2004. 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.
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
2005 2004 2005 2004
-------------------------------------------------------------------------
Operating costs ($000)
Field expenses 5,347 3,984 17,609 12,187
Processing and gathering income (1,354) (2,031) (5,063) (4,977)
-------------------------------------------------------------------------
Total operating costs 3,993 1,953 12,546 7,210
-------------------------------------------------------------------------
$/boe 1.95 1.03 1.55 1.05
-------------------------------------------------------------------------
Transportation 1,433 1,456 5,520 4,767
-------------------------------------------------------------------------
$/boe 0.70 0.77 0.68 0.70
-------------------------------------------------------------------------
Operating costs were $4.0 million in the fourth quarter of 2005 compared
to $2.0 million during the same period a year earlier. Peyto's high level of
drilling activity during 2005 resulted in a producing well count increase of
over 35%. The fixed cost structure associated with these wells combined with a
general inflationary effect of over 20% in the service sector caused the
overall cost increase.
On a unit-of-production basis, operating costs averaged $1.95/boe in the
fourth quarter of 2005 compared to $1.03/boe for the fourth quarter of 2004.
Operating costs for the year averaged $1.55/boe in 2005 compared to $1.05/boe
in 2004.
Netbacks
Operating netbacks represent the profit margin associated with the
production and sale of petroleum and natural gas. The primary factors that
produce Peyto's strong netbacks are a low cost structure and the high heat
content of our natural gas that results in higher commodity prices.
-------------------------------------------------------------------------
Three Months ended Twelve Months ended
Dec. 31 Dec. 31
($/boe) 2005 2004 2005 2004
-------------------------------------------------------------------------
Sale Price 62.36 45.78 53.23 43.93
Less:
Royalties 16.38 11.08 13.17 10.39
Operating costs 1.95 1.03 1.55 1.05
Transportation 0.70 0.77 0.68 0.70
-------------------------------------------------------------------------
Operating netback 43.33 32.90 37.83 31.79
General and administrative 0.05 0.01 0.08 0.12
Interest on long-term debt 0.91 1.03 1.07 1.01
Capital tax 0.06 0.16 0.06 0.09
-------------------------------------------------------------------------
Cash netback 42.31 31.69 36.62 30.57
-------------------------------------------------------------------------
General and Administrative Expenses
-------------------------------------------------------------------------
Three Months ended Twelve Months ended
Dec. 31 Dec. 31
2005 2004 2005 2004
-------------------------------------------------------------------------
G&A expenses ($000) 1,874 1,451 6,434 4,593
Overhead recoveries (1,778) (1,441) (5,754) (3,790)
-------------------------------------------------------------------------
Net G&A expenses 96 10 680 803
-------------------------------------------------------------------------
$/boe 0.05 0.01 0.08 0.12
-------------------------------------------------------------------------
General and administrative expenses before overhead recoveries increased
to $1.9 million in the fourth quarter of 2005, as compared to $1.5 million for
the same period in 2004 primarily due to staffing increases required to manage
our active drilling program and increasing property base. Net of overhead
recoveries associated with our capital expenditures program, general and
administrative costs increased to $0.05 per boe in the fourth quarter of 2005,
from $0.01 per boe in the fourth quarter of 2004. General and administrative
expenses for 2005 averaged $0.08/boe in 2005 compared to $0.12 in 2004.
Interest Expense
-------------------------------------------------------------------------
Three Months ended Twelve Months ended
Dec. 31 Dec. 31
2005 2004 2005 2004
-------------------------------------------------------------------------
Interest expense ($000) 1,857 1,964 8,702 6,905
$/boe 0.91 1.03 1.07 1.01
-------------------------------------------------------------------------
2005 interest expense was $8.7 million or $1.07/boe compared to
$6.9 million or $1.01/boe a year earlier. Interest rates continue to be
favorable and are not expected to increase substantially in the short term.
Depletion, Depreciation and Accretion
The 2005 provision for depletion, depreciation and accretion totaled
$58.2 million as compared to $40.9 million in 2004. On a unit-of-production
basis, depletion, depreciation and accretion costs averaged $7.18/boe as
compared to $5.98/boe in 2004. Increases or decreases in the depletion rate on
a unit of production basis are influenced by the reserves added through
Peyto's drilling program. As set out under the section "Critical Accounting
Estimates", Peyto adopted the CICA pronouncement with respect to Asset
Retirement Obligations, effective January 1, 2004.
Income Taxes
The current provision for future income tax increased to $37.6 million in
2005 from $25.6 million in 2004. Included in the 2005 provision was an amount
of $8.8 million recorded in the fourth quarter. Our trust structure is unique
in that it was designed to provide for discretion at the operating trust level
to distribute taxable income to the Trust. Given the significant level of
capital expenditures incurred by Peyto in the fourth quarter, the operating
trust had additional resource pool deductions available for use which give
rise to temporary differences which increased future income taxes in the
fourth quarter. Unitholders benefit as the use of these resource pools
increases the tax free return of capital component of the cash distributions.
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 2005, we recorded a hedging loss of $39.6 million as compared
to a hedging gain of $1.7 million in 2004. 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, 2006 Fixed price 300 bbl $53.85/bbl
January 1 to March 31, 2006 Fixed price 200 bbl $54.58/bbl
January 1 to March 31, 2006 Fixed price 300 bbl $57.65/bbl
January 1 to March 31, 2006 Fixed price 200 bbl $58.90/bbl
January 1 to March 31, 2006 Fixed price 200 bbl $65.21/bbl
January 1 to March 31, 2006 Fixed price 100 bbl $69.40/bbl
April 1 to June 30, 2006 Fixed price 200 bbl $64.75/bbl
April 1 to June 30, 2006 Fixed price 200 bbl $64.62/bbl
April 1 to June 30, 2006 Fixed price 200 bbl $68.64/bbl
April 1 to June 30, 2006 Fixed price 300 bbl $76.00/bbl
April 1 to June 30, 2006 Fixed price 200 bbl $81.00/bbl
July 1 to September 30, 2006 Fixed price 200 bbl $70.00/bbl
July 1 to September 30, 2006 Fixed price 200 bbl $72.15/bbl
July 1 to September 30, 2006 Fixed price 300 bbl $75.40/bbl
July 1 to September 30, 2006 Fixed price 200 bbl $80.10/bbl
October 1 to December 31, 2006 Fixed price 200 bbl $69.40/bbl
October 1 to December 31, 2006 Fixed price 200 bbl $71.10/bbl
October 1 to December 31, 2006 Fixed price 200 bbl $79.00/bbl
Natural Gas Price
Period Hedged Type Daily Volume (CAD)
-------------------------------------------------------------------------
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $7.40/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $7.50/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $7.60/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $7.70/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $7.80/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $7.91/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $8.01/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $8.15/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $8.22/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $8.32/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $8.50/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $8.72/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $8.55/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $9.00/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $9.75/GJ
April 1 to October 31, 2006 Fixed price 5,000 GJ $7.10/GJ
April 1 to October 31, 2006 Fixed price 5,000 GJ $7.20/GJ
April 1 to October 31, 2006 Fixed price 5,000 GJ $7.30/GJ
April 1 to October 31, 2006 Fixed price 5,000 GJ $7.35/GJ
April 1 to October 31, 2006 Fixed price 5,000 GJ $7.45/GJ
April 1 to October 31, 2006 Fixed price 5,000 GJ $7.61/GJ
April 1 to October 31, 2006 Fixed price 5,000 GJ $7.75/GJ
April 1 to October 31, 2006 Fixed price 5,000 GJ $9.30/GJ
April 1 to October 31, 2006 Fixed price 5,000 GJ $10.60/GJ
April 1 to October 31, 2006 Fixed price 5,000 GJ $10.60/GJ
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
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. Currently we have not entered into any
agreements to 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, 2005, the increase or
decrease in earnings for each 100 bps change in interest rate paid on the
outstanding revolving demand loan amounts to approximately $2.2 million per
annum.
LIQUIDITY AND CAPITAL RESOURCES
Funds from Operations
-------------------------------------------------------------------------
Three Months ended Twelve Months ended
Dec. 31 Dec. 31
($000) 2005 2004 2005 2004
-------------------------------------------------------------------------
Net earnings 60,745 (2,558) 161,568 73,782
Items not requiring cash:
Non-cash provision for
(recovery of) performance
based compensation (57,459) (15,966) (18,271) 15,945
Future income tax expense 8,832 15,140 37,618 25,558
Depletion, depreciation &
accretion 16,642 10,777 58,208 40,880
Non-recurring items:
Market and reserve value
performance based
compensation 57,847 52,941 57,847 52,941
-------------------------------------------------------------------------
Funds from operations 86,607 60,334 296,970 209,106
-------------------------------------------------------------------------
For the quarter ended December 31, 2005, funds from operations totaled
$86.6 million or $0.85 per unit, representing a 31 percent increase from the
$60.3 million, or $0.65 per unit during the same period in 2004. For fiscal
2005 funds from operations totaled $297.0 million or $3.01 per unit compared
to $209.1 million or $2.28 per unit in 2004. 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 highly 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 $350 million including a $330 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
2005 was 4.0% (2004 - 3.7%).
At December 31, 2005, $180 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, 2005, we had a working capital
deficit of $116.5 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. Every year since Peyto started our capital expenditures have grown.
We expect that this will again be the case in 2006. The total amount of
capital we ultimately invest in 2006 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. During the
year, Peyto will be constructing two new gas plants to ensure that we can
efficiently access the new reserves we are finding. 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.
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. On January 13, 2006 35,284
trust units (30,004 pursuant to the DRIP and 5,280 pursuant to the OTUPP) were
issued for net proceeds of $882,100.
At December 31, 2005 units to be issued were 1,116,854 on account of the
December 31, 2005 private placement, and the December, 2005 Distribution
Reinvestment Plan/Optional Trust Unit Purchase Plan. On January 13, 2006,
subsequent to the issuance of these units, 103,450,701 trust units were
outstanding (December 31, 2005 - 102,333,847).
Authorized: Unlimited number of voting trust units
Issued and Outstanding:
Number of Amount
Trust Units (no par value) Shares/Units $
-------------------------------------------------------------------------
Balance, December 31, 2003 45,395,122 49,227,530
Trust units issued by private placement 330,150 9,013,095
Trust units issued 2,000,000 85,300,000
Trust unit issue costs - (4,587,599)
Balance, December 31, 2004 47,725,272 138,953,026
Trust units issued by private placement 670,000 31,586,375
Trust unit issue costs - (103,010)
Trust units issued pursuant to DRIP 28,645 1,356,148
Trust units issued pursuant to 2 for 1 split 48,423,917 -
Trust units issued by public offering 5,000,000 152,750,000
Trust unit issue costs - (8,054,775)
Trust units issued pursuant to DRIP 279,561 7,448,146
Trust units issued pursuant to OTUPP 206,452 4,800,000
-------------------------------------------------------------------------
Balance, December 31, 2005 102,333,847 328,735,910
-------------------------------------------------------------------------
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%.
-------------------------------------------------------------------------
($ million except unit values) 2005 2004 Change
-------------------------------------------------------------------------
Net present value of proved producing
reserves (at) 8% based on constant
Paddock Lindstrom 2005 price forecast 2,121.0 1,691.0
Net debt before performance based
compensation (257.4) (223.0)
2005 distributions - (136.6)
---------------------------------
Net value 1,863.6 1,331.4 532.2
Equity adjustment factor(x) 80%
-------------
Equity adjusted increase in value 427.1
-------------
2005 reserve value based compensation
(at) 3% $12.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 2005 market based component was based on 2.0 million
vested rights at an average grant price of $10.82, average cumulative
distributions of $4.36 and the five day weighted average closing price of
$25.38 (2004 - 2.0 million rights, average grant price of $8.41, average
cumulative distributions of $1.365 per unit and five day weighted average
closing price of $23.77, all 2004 comparatives adjusted to reflect the May 31,
2005 2 for 1 unit split). In the fourth quarter of 2005, 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:
-------------------------------------------------------------------------
2005 2004
$ $
-------------------------------------------------------------------------
Market based compensation 45,045,054 44,607,873
Reserve value based compensation 12,802,000 8,333,000
-------------------------------------------------------------------------
Total 57,847,054 52,940,873
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Compensation costs as at December 31, 2005 related to 2.6 million
non-vested rights with an average grant price of $20.31 was $21.7 million of
which a non-cash provision for future compensation expense of $6.1 million was
recorded at December 31, 2004 and an additional $4.0 million was recorded in
2005.
Capital Expenditures
Net capital expenditures for the fourth quarter of 2005 totaled
$107.6 million. Exploration and development related activity represented
$91.3 million or 85% of the total, while expenditures on facilities, gathering
systems and equipment totaled $16.3 million or 15% of the total. The following
table summarizes capital expenditures for the year.
-------------------------------------------------------------------------
Three Months ended Twelve Months ended
Dec. 31 Dec. 31
($000) 2005 2004 2005 2004
-------------------------------------------------------------------------
Land 3,657 772 12,324 3,975
Seismic 3,309 3,314 11,559 5,768
Drilling - Exploratory &
Development 84,189 61,007 274,360 167,742
Production Equipment,
Facilities & Pipelines 16,308 11,799 59,810 49,898
Acquisitions & Dispositions - 52 - 3,307
Office Equipment 184 9 401 84
-------------------------------------------------------------------------
Total Capital Expenditures 107,647 76,953 358,454 230,774
-------------------------------------------------------------------------
Cash Distributions
-------------------------------------------------------------------------
Three Months ended Twelve Months ended
Dec. 31 Dec. 31
($000) 2005 2004 2005 2004
-------------------------------------------------------------------------
Funds from operations ($000) 86,607 60,334 296,970 209,106
Distributions ($000) 36,773 26,443 136,648 93,660
Distributions per unit ($)(x) 0.36 0.285 1.39 1.02
Payout ratio (%) 42 44 46 45
-------------------------------------------------------------------------
(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. Management 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:
-------------------------------------------------------------------------
$
-------------------------------------------------------------------------
2006 953,484
2007 953,484
2008 1,096,641
2009 1,096,641
2010 1,096,641
2011 1,096,641
-------------------------------------------------------------------------
6,293,532
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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.
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 2005, the Trust paid distributions to the unitholders in the
amount of $136.7 million (2004 - $93.7 million) in accordance with the
following schedule:
Production Period Record Date Distribution Date Per Unit(x)
---------------------------------------------------------------------
January 2005 January 31, 2005 February 15, 2005 $0.095
February 2005 February 28, 2005 March 13, 2005 $0.11
March 2005 March 31, 2005 April 15, 2005 $0.11
April 2005 April 29, 2005 May 15, 2005 $0.11
May 2005 May 31, 2005 June 15, 2005 $0.12
June 2005 June 30, 2005 July 15, 2005 $0.12
July 2005 July 29, 2005 August 15, 2005 $0.12
August 2005 August 31, 2005 September 15, 2005 $0.12
September 2005 September 30, 2005 October 14, 2005 $0.12
October 2005 October 31, 2005 November 15, 2005 $0.12
November 2005 November 30, 2005 December 15, 2005 $0.12
December 2005 December 28, 2005 January 13, 2006 $0.12
-----------
$1.385
-----------
-----------
(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 equity.
DISCLOSURE CONTROLS AND PROCEDURES
Disclosure controls and procedures are designed to provide reasonable
assurance that all relevant information is gathered and reported to senior
management, including the Chief Executive Officer ("CEO") and Vice President,
Finance ("VPF"), on a timely basis so that appropriate decisions can be made
regarding public disclosure.
As of the end of the period covered by this report, Peyto's management
evaluated the effectiveness of the design and operation of its disclosure
controls and procedures, under the supervision of, and with the participation
of the CEO and VPF. Based on this evaluation, the CEO and VPF have concluded
that Peyto's disclosure controls and procedures, as defined in Multilateral
Instrument 52-109, Certification of Disclosure in Issuers Annual and Interim
Filings are effective to ensure that material information relating to Peyto is
made known to management on a timely basis and is included in this report.
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, 2005 were audited by independent petroleum engineers Paddock
Lindstrom & Associates Ltd. Paddock has been evaluating reserves in this area
and for Peyto for 7 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 2006. 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 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.
ADDITIONAL INFORMATION
Additional information relating to Peyto Energy Trust can be found on
SEDAR at www.sedar.com and www.peyto.com.
Quarterly information
-------------------------------------------------------------------------
2005 2004
Q4 Q3 Q2 Q1 Q4
-------------------------------------------------------------------------
Operations
Production
Natural gas
(mcf/d) 108,356 108,460 106,866 103,043 97,968
Oil & NGLs
(bbl/d) 4,185 4,569 4,653 4,337 4,360
Barrels of oil
equivalent
(boe/d (at)
6:1) 22,245 22,646 22,464 21,511 20,688
Average product
prices
Natural gas
($/mcf) 10.55 8.67 8.00 7.81 7.58
Oil & natural
gas liquids
($/bbl) 58.43 57.22 51.03 55.52 46.82
Average operating
expenses ($/boe) 1.95 1.70 1.30 1.22 1.03
Average
transportation
costs ($/boe) 0.70 0.66 0.68 0.68 0.77
Field netback
($/boe) 43.33 38.39 33.97 35.50 32.90
General &
administrative
expense ($/boe) 0.05 0.13 0.10 0.06 0.01
Interest expense
($/boe) 0.91 1.16 1.25 0.97 1.03
Financial
($000 except
per unit)
Revenue 127,633 110,566 99,427 94,069 87,127
Royalties (net
of ARTC) 33,522 25,654 25,954 21,672 21,103
Funds from
operations 86,607 77,179 66,548 66,636 60,334
Funds from
operations
per unit(x) 0.85 0.78 0.69 0.69 0.65
Cash
distributions 36,773 35,505 33,898 30,472 26,443
Cash
distributions
per unit(x) 0.36 0.36 0.35 0.315 0.285
Percentage of funds
from operations
distributed 42% 46% 51% 46% 44%
Earnings 60,745 37,702 25,690 37,431 (2,558)
Earnings per
diluted
unit(x) 0.60 0.38 0.27 0.39 (0.03)
Capital
expenditures 107,647 93,001 58,730 99,074 76,953
Weighted average
trust units
outstan-
ding(x) 102,148,411 98,584,597 96,848,988 96,664,210 92,494,022
(x) Note: prior periods restated for 2 for 1 split of trust units
completed May 31, 2005.
Peyto Energy Trust
Consolidated Balance Sheets
(unaudited)
December 31, December 31,
2005 2004
$ $
-------------------------------------------------------------------------
Assets
Current
Accounts receivable 82,793,463 58,992,005
Due from private placements (Note 6) 27,450,247 27,080,066
Prepaid expenses and deposits 1,795,540 5,262,778
-------------------------------------------------------------------------
112,039,250 91,334,849
Property, plant and equipment (Note 3) 832,887,287 531,241,786
-------------------------------------------------------------------------
944,926,537 622,576,635
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities and Unitholders' Equity
Current
Accounts payable and accrued liabilities 208,284,019 124,753,199
Capital taxes payable 110,412 483,081
Cash distributions payable 11,529,973 9,067,811
Provision for future performance based
compensation (Note 10) 8,748,198 22,298,937
-------------------------------------------------------------------------
228,672,602 156,603,028
-------------------------------------------------------------------------
Long-term debt (Note 4) 180,000,000 180,000,000
Provision for future performance based
compensation (Note 10) 1,400,970 6,121,097
Asset retirement obligations (Note 5) 4,729,098 3,328,834
Future income taxes (Note 11) 108,292,966 70,675,002
-------------------------------------------------------------------------
294,423,034 260,124,933
-------------------------------------------------------------------------
Unitholders' equity
Unitholders' capital (Note 6) 328,735,910 138,953,026
Units to be issued (Note 6) 28,332,345 27,052,850
Accumulated earnings 335,925,837 174,358,093
Accumulated cash distributions (Note 7) (271,163,191) (134,515,295)
-------------------------------------------------------------------------
421,830,901 205,848,674
-------------------------------------------------------------------------
944,926,537 622,576,635
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
On behalf of the Board:
(signed) "Michael MacBean" (signed) "Donald T. Gray"
Director Director
Peyto Energy Trust
Consolidated Statements of Earnings and Accumulated Earnings
For the years ended December 31,
2005 2004
$ $
-------------------------------------------------------------------------
Revenue
Petroleum and natural gas sales, net 324,892,613 229,412,031
-------------------------------------------------------------------------
Expenses
Operating (Note 8) 12,546,248 7,210,155
Transportation 5,520,140 4,766,755
General and administrative (Note 9) 679,529 803,458
Performance based compensation (Note 10) 57,847,054 52,940,873
Future performance based compensation
provision (Note 10) (18,270,866) 15,944,936
Interest on long term debt 8,701,501 6,904,809
Depletion, depreciation and accretion
(Note 3 and 5) 58,208,298 40,879,937
-------------------------------------------------------------------------
125,231,904 129,450,923
-------------------------------------------------------------------------
Earnings before taxes 199,660,709 99,961,108
-------------------------------------------------------------------------
Taxes
Future income tax expense (Note 11) 37,617,965 25,558,297
Capital tax expense 475,000 621,177
-------------------------------------------------------------------------
38,092,965 26,179,474
-------------------------------------------------------------------------
Net earnings for the year 161,567,744 73,781,634
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Accumulated earnings, beginning of year 174,358,093 100,576,459
-------------------------------------------------------------------------
Accumulated earnings, end of year 335,925,837 174,358,093
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per unit (Note 6)
Basic 1.64 0.805
Diluted 1.64 0.805
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
Peyto Energy Trust
Consolidated Statements of Cash Flows
For the years ended December 31,
2005 2004
$ $
-------------------------------------------------------------------------
Cash provided by (used in)
Operating Activities
Net earnings for the year 161,567,744 73,781,634
Items not requiring cash:
Non-cash provision for (recovery of)
performance based compensation (18,270,866) 15,944,936
Future income tax expense 37,617,965 25,558,297
Depletion, depreciation and accretion 58,208,298 40,879,937
Change in non-cash working capital related
to operating activities (Note 13) 35,776,839 5,029,631
-------------------------------------------------------------------------
274,899,980 161,194,435
-------------------------------------------------------------------------
Financing Activities
Issue of trust units, net of costs 191,062,379 107,765,251
Distribution payments (136,647,896) (93,659,685)
Increase in bank debt - 30,000,000
Change in non-cash working capital related
to financing activities (Note 13) 2,091,981 (15,808,428)
-------------------------------------------------------------------------
56,506,464 28,297,138
-------------------------------------------------------------------------
Investing Activities
Additions to property, plant and equipment (358,453,535) (230,773,505)
Change in non-cash working capital related
to investing activities (Note 13) 27,047,091 20,690,714
-------------------------------------------------------------------------
(331,406,444) (210,082,791)
-------------------------------------------------------------------------
Net increase (decrease) in cash - (20,591,218)
Cash, beginning of year - 20,591,218
-------------------------------------------------------------------------
Cash, end of year - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
Peyto Energy Trust
Notes to Consolidated Financial Statements
December 31, 2005 and 2004
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. 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 assets is not assessed 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
2005 2004
$ $
---------------------------------------------------------------------
Property, plant and equipment 976,005,103 616,422,327
Accumulated depletion and depreciation (143,117,816) (85,180,541)
---------------------------------------------------------------------
832,887,287 531,241,786
---------------------------------------------------------------------
---------------------------------------------------------------------
At December 31, 2005 costs of $33,617,224 (December 31, 2004 -
$28,663,020) related to undeveloped land have been excluded from the
depletion and depreciation calculation.
The Trust performed a ceiling test calculation at December 31, 2005
resulting in the undiscounted cash flows from proved reserves plus
the lower of cost and market of unproved properties exceeding the
carrying value of petroleum and natural gas assets. The impairment
test was calculated at December 31, 2005 using the following
independent engineering consultant's forecasted prices:
There-
after
2006 2007 2008 2009 2010 (2)
---------------------------------------------------------------------
Edmonton Ref Price
($CDN/bbl)(1) 69.57 66.61 63.64 60.68 57.72 +2%
---------------------------------------------------------------------
AECO ($CDN/mmbtu) 10.54 9.52 8.32 7.71 7.10 +2%
---------------------------------------------------------------------
(1) Future prices incorporated a $0.85 US/CDN exchange rate.
(2) Percentage change of 2.0% represents the change in future prices
each year after 2010 to the end of the reserve life.
4. Long-Term Debt
The Trust has a syndicated $350 million extendible revolving credit
facility. The facility is made up of a $20 million working capital
sub-tranche and a $330 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 cash flow 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 2005 was 4.0% (2004 - 3.7%).
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 $4.7 million as at
December 31, 2005 based on a total future liability of $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:
2005 2004
$ $
---------------------------------------------------------------------
Carrying amount, beginning of year 3,328,834 2,279,411
Increase in liabilities during the
period 1,129,241 860,453
Settlement of liabilities during the
period - -
Accretion expense 271,023 188,970
---------------------------------------------------------------------
Carrying amount, end of year 4,729,098 3,328,834
---------------------------------------------------------------------
---------------------------------------------------------------------
6. Unitholders' Capital
Authorized: Unlimited number of voting trust units
Issued and Outstanding
Number of Amount
Trust Units (no par value) Shares/Units $
--------------------------------------------------------------------
Balance, December 31, 2003 45,395,122 49,227,530
Trust units issued by private placement 330,150 9,013,095
Trust units issued by public offering 2,000,000 85,300,000
Trust unit issue costs - (4,587,599)
Balance, December 31, 2004 47,725,272 138,953,026
Trust units issued by private placement 670,000 31,586,375
Trust unit issue costs - (103,010)
Trust units issued pursuant to
Distribution Reinvestment Plan (DRIP) 28,645 1,356,148
Trust units issued pursuant to
2 for 1 split 48,423,917 -
Trust units issued by public offering 5,000,000 152,750,000
Trust unit issue costs - (8,054,775)
Trust units issued pursuant to DRIP 279,561 7,448,146
Trust units issued pursuant to Optional
Trust Unit Purchase Plan (OTUPP) 206,452 4,800,000
--------------------------------------------------------------------
Balance, December 31, 2005 102,333,847 328,735,910
--------------------------------------------------------------------
--------------------------------------------------------------------
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.
Units to be Issued
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. On
January 13, 2006 35,284 trust units (30,004 pursuant to the DRIP and
5,280 pursuant to the OTUPP) were issued for net proceeds of
$882,100. On December 31, 2004 the Trust completed a private
placement of 582,500 trust units to employees and consultants for net
proceeds of $27,052,850. The trust units were issued on January 4,
2005.
Per Unit Amounts
Earnings per unit have been calculated based upon the weighted
average number of units outstanding during the year of 98,576,640
(2004 -91,711,034). There are no dilutive instruments outstanding.
(x) Note: prior periods have been restated for 2 for 1 split of
trust units completed May 31, 2005.
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.
The total amount payable by the Trust in respect of the redemption of
all Trust Units tendered for redemption shall not exceed $100,000 in
the same calendar month, however such limitation may be waived by the
Trust.
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. Management 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 $136.7 million (2004 - $93.7 million) in
accordance with the following schedule:
Per
Production Period Record Date Distribution Date Unit(x)
---------------------------------------------------------------------
January 2005 January 31, 2005 February 15, 2005 $0.095
February 2005 February 28, 2005 March 13, 2005 $0.11
March 2005 March 31, 2005 April 15, 2005 $0.11
April 2005 April 29, 2005 May 15, 2005 $0.11
May 2005 May 31, 2005 June 15, 2005 $0.12
June 2005 June 30, 2005 July 15, 2005 $0.12
July 2005 July 29, 2005 August 15, 2005 $0.12
August 2005 August 31, 2005 September 15, 2005 $0.12
September 2005 September 30, 2005 October 14, 2005 $0.12
October 2005 October 31, 2005 November 15, 2005 $0.12
November 2005 November 30, 2005 December 15, 2005 $0.12
December 2005 December 28, 2005 January 13, 2006 $0.12
(x) Note: prior periods have been restated for 2 for 1 split of
trust units completed May 31, 2005.
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.
2005 2004
$ $
---------------------------------------------------------------------
Field expenses 17,609,057 12,187,102
Processing and gathering income (5,062,809) (4,976,947)
---------------------------------------------------------------------
Total operating costs 12,546,248 7,210,155
---------------------------------------------------------------------
---------------------------------------------------------------------
9. General and Administrative Expenses
General and administrative expenses are reduced by operating and
capital overhead recoveries from operated properties.
2005 2004
$ $
---------------------------------------------------------------------
G&A expenses 6,434,136 4,593,048
Overhead recoveries (5,754,607) (3,789,590)
---------------------------------------------------------------------
Net G&A expenses 679,529 803,458
---------------------------------------------------------------------
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%.
---------------------------------------------------------------------
($ million except unit values) 2005 2004 Change
---------------------------------------------------------------------
Net present value of proved producing
reserves (at) 8% based on constant
Paddock Lindstrom 2005 price
forecast 2,121.0 1,691.0
Net debt before performance based
compensation (257.4) (223.0)
2005 distributions - (136.6)
-------------------------------
Net value 1,863.6 1,331.4 532.2
Equity adjustment factor(x) 80%
---------
Equity adjusted increase in value 427.1
---------
2005 reserve value based
compensation (at) 3% $12.8
---------------------------------------------------------------------
---------------------------------------------------------------------
(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 2005 market based component was
based on 2.0 million vested rights at an average grant price of
$10.82, average cumulative distributions of $4.36 and the five day
weighted average closing price of $25.38 (2004 - 2.0 million rights,
average grant price of $8.41, average cumulative distributions of
$1.365 per unit and five day weighted average closing price of
$23.77, all 2004 comparatives adjusted to reflect the May 31, 2005
2 for 1 unit split). In the fourth quarter of 2005, 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:
2005 2004
$ $
---------------------------------------------------------------------
Market based compensation 45,045,054 44,607,873
Reserve value based compensation 12,802,000 8,333,000
---------------------------------------------------------------------
Total 57,847,054 52,940,873
---------------------------------------------------------------------
---------------------------------------------------------------------
For the market based component, compensation costs as at December 31,
2005 related to 2.6 million non-vested rights with an average grant
price of $20.31 was $21.7 million of which a non-cash provision for
future compensation expense of $6.1 million was recorded at
December 31, 2004 and an additional $4.0 million was recorded in
2005.
11. Future Income Taxes
2005 2004
$ $
---------------------------------------------------------------------
Earnings before income taxes 199,660,706 99,961,108
Statutory income tax rate 37.62% 38.87%
---------------------------------------------------------------------
Expected income taxes 75,112,358 38,854,882
Increase (decrease) in income taxes from:
Non-deductible crown charges 24,372,435 19,990,378
Resource allowance (21,705,862) (15,714,733)
Corporate income tax rate change (370,683) -
Attributed Canadian Royalty Income (ACRI) (1,023,253) 2,205,065
Income attributed to the trust (38,423,907) (20,917,147)
Change in valuation allowance for share
issue costs (994,416) -
Other 651,293 1,139,852
---------------------------------------------------------------------
Future income tax expense 37,617,965 25,558,297
---------------------------------------------------------------------
---------------------------------------------------------------------
The net future income tax liability comprises:
2005 2004
$ $
---------------------------------------------------------------------
Differences between tax base and reported
amounts for depreciable assets 112,788,707 81,931,159
Accrued expenditures (2,858,527) (10,103,715)
Provision for asset retirement obligation (1,637,214) (1,152,442)
---------------------------------------------------------------------
108,292,966 70,675,002
---------------------------------------------------------------------
---------------------------------------------------------------------
At December 31, 2005 the Trust has tax pools of approximately
$582.4 million (December 31, 2004 - $303.9 million) available for
deduction against future income. Peyto Energy Trust has
approximately $9.3 million in unrecognized future income tax assets
available to reduce future taxable income.
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, 2005 is as follows:
Weighted
Crude Oil Daily Average
Period Hedged Type Volume Price (CAD)
---------------------------------------------------------------------
January 1 to March 31, 2006 Fixed price 1,300 bbl $58.56/bbl
April 1 to June 30, 2006 Fixed price 1,100 bbl $71.46/bbl
July 1 to September 30, 2006 Fixed price 900 bbl $74.52/bbl
October 1 to December 31, 2006 Fixed price 600 bbl $73.17/bbl
Weighted
Natural Gas Daily Average
Period Hedged Type Volume Price (CAD)
---------------------------------------------------------------------
Nov. 1, 2005 to March 31, 2006 Fixed price 75,000 GJ $8.21/GJ
April 1 to October 31, 2006 Fixed price 50,000 GJ $8.23/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 35,000 GJ $10.01/GJ
As at December 31, 2005, the Trust had committed to the future sale
of 355,100 barrels of crude oil at an average price of $68.19 per
barrel and 22,735,000 gigajoules (GJ) of natural gas at an average
price of $8.64 per GJ or $10.11 per mcf based on the historical
heating value of Peyto's natural gas. These contracts will generate
revenue totaling $220.6 million. Based on the market's estimate of
the future commodity prices as at December 31, 2005 the fair value of
these contracts would be $261.4 million.
Subsequent to December 31, 2005 the Trust entered into the following
contracts:
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
Fair Values of Financial Assets and Liabilities
The Trust's financial instruments include accounts receivable, due
from private placement, current liabilities, provision for future
market performance based compensation and long term debt. At
December 31, 2005, the carrying value of accounts receivable, due
from private placement, 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, 2005, approximately 42% was due from one company
(December 31, 2004 - 50%).
The Trust may be exposed to certain losses in the event of
non-performance by counter-parties to commodity price contracts. The
Trust mitigates this risk by entering into transactions with
counter-parties that have investment grade credit ratings.
Interest rate risk
The Trust is exposed to interest rate risk in relation to interest
expense on its revolving demand facility. At December 31, 2005, the
increase or decrease in earnings for each 1% change in interest rate
paid on the outstanding revolving demand loan amounts to
approximately $2.2 million per annum.
13. Supplemental Cash Flow Information
Changes in non-cash working capital balances
2005 2004
$ $
---------------------------------------------------------------------
Accounts receivable (23,801,458) (17,881,727)
Due from private placement (370,181) (130,497)
Prepaid expenses and deposits 3,467,237 (18,066,972)
Accounts payable and accrued liabilities 83,530,820 43,326,215
Capital taxes payable (372,669) 406,355
Cash distributions payable 2,462,162 2,258,543
---------------------------------------------------------------------
64,915,911 9,911,917
Attributable to financing activities 2,091,981 (15,808,428)
Attributable to investing activities 27,047,091 20,690,714
---------------------------------------------------------------------
Attributable to operating activities 35,776,839 5,029,631
---------------------------------------------------------------------
---------------------------------------------------------------------
2005 2004
$ $
---------------------------------------------------------------------
Cash interest paid during the year 8,701,501 6,904,809
Cash taxes paid during the year 847,669 214,822
---------------------------------------------------------------------
---------------------------------------------------------------------
14. Commitments
The Trust is committed to payments under operating leases for office
space as follows:
$
---------------------------------------------------------------------
2006 953,484
2007 953,484
2008 1,096,641
2009 1,096,641
2010 1,096,641
2011 1,096,641
---------------------------------------------------------------------
6,293,532
---------------------------------------------------------------------
---------------------------------------------------------------------
15. Subsequent Events
On February 14, 2006, on private placement basis, 312,370 trust units
were issued to employees and consultants at a price of $22.18 per
trust unit for proceeds for $6.9 million.
Peyto Exploration & Development Corp. Information
Officers
Don Gray Glenn Booth
President and Chief Executive Officer Vice President, Land
Ken Veres Kathy Turgeon
Vice-President, Exploration Vice President, Finance
Darren Gee Stephen Chetner
Vice President, Engineering Corporate Secretary
Scott Robinson Cheree Stephenson
Vice President, Operations Controller
Directors
Ian Mottershead
Rick Braund
Don Gray
Brian Craig
Roberto Bosdachin
John Boyd
Michael MacBean
Auditors
Deloitte & Touche LLP
Solicitors
Burnet, Duckworth & Palmer LLP
Bankers
Bank of Montreal
Union Bank of California
Canadian Imperial Bank of Commerce
Royal Bank of Canada
BNP Paribas
Transfer Agent
Valiant Trust Company
Head Office
2900, 450 - 1st Street SW
Calgary, AB
T2P 5H1
Phone: 403.261.6081
Fax: 403.261.8976
Web: www.peyto.com
Stock Listing Symbol: PEY.un
Toronto Stock Exchange
>>
%SEDAR: 00019597E
