SYMBOL: PEY.UN - TSX
CALGARY, Aug. 9 /CNW/ - Peyto Energy Trust ("Peyto") is pleased to
present the operating and financial results for the second quarter of the 2006
fiscal year. Peyto has a solid foundation made up of high quality, long life,
natural gas assets, and a business with an eight year track record of
successfully achieving premium returns on the capital we invest. We continue
to design, drill and build our own assets in Alberta's premier gas exploration
area, the Deep Basin.
<<
The following summarizes the Trust's foundation.
- Long reserve life Proved 13.6 years, Proved Plus Probable 18.9 years
at the end of 2005
- Low operating costs $2.26/boe, three months ending June 30, 2006
- Low base general and administrative costs $0.43/boe, three months
ending June 30, 2006
- High revenue per boe - $45.93/boe, before hedging, $51.24/boe, after
hedging, three months ending June 30, 2006
- High field netback - $39.64/boe, three months ending June 30, 2006
- High operatorship - we operate over 95% of our production
- Low cash distribution payout ratio - cash distributions were 49% of
funds from operations for the three months ended June 30, 2006
- Low debt to funds from operations ratio - 1.3 (net debt, before
provision for future compensation, divided by annualized second
quarter 2006 funds from operations)
- Distribution growth - distributions have been increased 5 times and
are now 87% higher than when the trust was formed in July 2003.
- Since inception, Peyto has raised a total of $387 million issuing
units from treasury, accumulated earnings of $438 million, and
distributed $357 million to unitholders
- Transparent capital structure - no convertible debentures, no
exchangeable shares, no stock options, no warrants
The following summarizes performance highlights of the business for the
second quarter of 2006.
- Production growth - production increased 2% from 22,464 boe/d in the
second quarter of 2005 to 22,892 boe/d in the second quarter of 2006
- Production per unit - decreased 8% per trust unit from the second
quarter of 2005, after adjusting for debt and future unrealized
performance based compensation
- Per unit funds from operations growth - grew 8% from the previous
year to $0.74/unit
- Hedging - we had an $11.1 million gain for the second quarter versus
a $5.8 million loss in the first quarter of 2006 based on financial
instruments
- Capital expenditures - $67.2 million was invested into finding and
developing new natural gas reserves
- Distributions per unit increased by 20% from the second quarter of
2005 while the cash payout ratio remained low at 49% compared to 47%
in the second quarter of 2005. A total of $43.9 million or $0.42 per
unit was distributed to unitholders in the second quarter of 2006.
Natural gas volumes recorded in thousand cubic feet (mcf) are converted
to barrels of oil equivalent (boe) using the ratio of six (6) thousand
cubic feet to one (1) barrel of oil (bbl).
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3 Months Ended June 30 % 6 Months Ended June 30 %
2006 2005 Change 2006 2005 Change
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Operations
Production
Natural gas
(mcf/d) 112,484 106,866 5% 111,685 104,965 6%
Oil & NGLs
(bbl/d) 4,145 4,653 (11)% 4,144 4,495 (8)%
Barrels of
oil
equivalent
(boe/d at
6:1) 22,892 22,464 2% 22,758 21,990 3%
Product prices
Natural gas
($/mcf) 7.96 8.00 (1)% 8.60 7.91 9%
Oil & NGLs
($/bbl) 66.94 51.03 31% 62.06 53.18 17%
Operating expenses
($/boe) 2.26 1.30 74% 2.03 1.26 61%
Transportation
($/boe) 0.59 0.68 (13)% 0.61 0.68 (10)%
Field netback
($/boe) 39.64 33.97 17% 39.83 34.71 15%
General &
administrative
expenses ($/boe) 0.43 0.10 330% 0.25 0.08 213%
Interest expense
($/boe) 2.00 1.25 60% 1.69 1.11 52%
Financial ($000,
except per unit)
Revenue 106,751 99,427 7% 220,468 193,496 14%
Royalties
(net of ARTC) 18,236 25,954 (30)% 45,494 47,626 (4)%
Funds from
operations 77,507 66,548 16% 156,124 133,184 17%
Funds from
operations
per unit 0.74 0.69 7% 1.50 1.38 9%
Total
distributions 43,921 33,898 30% 85,439 64,370 33%
Total
distributions
per unit 0.42 0.35 20% 0.82 0.665 23%
Payout ratio 57 51 12% 55 48 15%
Cash distributions
(net of DRIP) 38,315 31,023 24% 72,980 61,005 20%
Payout ratio 49 47 4% 47 46 2%
Earnings 56,768 25,690 121% 102,061 63,121 62%
Earnings per
diluted unit 0.54 0.27 100% 0.98 0.65 51%
Capital
expenditures 67,195 58,730 14% 212,289 157,805 35%
Weighted average
trust units
outstanding 104,472,570 96,848,988 8% 104,333,091 96,757,110 8%
As at June 30
Net debt
(before future
compensation
expense) 399,963 304,165
Unitholders'
equity 467,978 212,395
Total assets 1,073,338 726,064
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3 Months Ended 6 Months Ended
June 30 June 30
2006 2005 2006 2005
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Net Earnings 56,768 25,690 102,061 63,121
Items not requiring cash:
Non-cash provision for
(recovery of) performance
based compensation (2,626) 21,118 2,196 25,045
Future income tax expense 2,878 5,261 11,555 17,730
Depletion, depreciation
and accretion 20,487 14,479 40,370 27,288
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Funds from operations(1) 77,507 66,548 156,124 133,184
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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.
Quarterly Review
In the second quarter, $67.2 million of capital was invested in building
new gas assets. Well related activity in the quarter accounted for
$59.2 million or 88% of the total. Seismic and land acquisitions made up
$4.5 million bringing the total investment in future drilling inventory to
$20.2 million for the first six months of 2006. We will begin to capitalize on
this inventory over the next 12 months. Costs associated with the new 20
mmcf/d Nosehill Gas Plant were $3.5 million of the total capital spent in the
quarter.
Peyto drilled and cased 15 gross (13.4 net) gas wells and completed 26
gross (20.5 net) gas zones in the quarter. A normal spring breakup restricted
access and thus, limited the number of new zones brought on production to 30
gross (19.7 net). Average production was 22,892 boe/d for the quarter.
Peyto's operating costs were $2.26/boe for the quarter, up from $1.81/boe
in the prior quarter. The average cost for the first six months of the year
was $2.03/boe. Although operating costs are higher than historic levels, the
reason for the increase is primarily due to inflation which is driven by
higher commodity prices. Some of the increase in operating costs is due to the
natural stabilization of our asset base which is more than offset by a
reduction in royalties. We believe Peyto's operating costs continue to lead
the industry by a wide margin.
The average price of natural gas quoted on the AECO monthly index
declined by 17% from the first quarter to the second quarter. Peyto's
marketing program resulted in a strong commodity price for gas of $7.96/mcf
and $66.94/bbl for oil and NGLs. These prices combined with our low operating
costs and lower royalties yielded field netbacks of $39.64/boe, which were 17%
higher than a year ago and effectively the same as the first quarter of 2006.
Activity Update
To date in 2006, Peyto has drilled 62 gross (49 net) wells and brought on
production 95 gross (77 net) zones accounting for approximately 6,000 boe/d of
new working interest production. The following table shows a breakdown of
Peyto's working interest production by area as compared to the same period for
the previous year.
<<
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Peyto Working Interest Sales (boe/d)
July July %
Area 2006 2005 Change
-------------------------------------------------------------------------
Sundance/Wildhay 18,690 14,830 26%
Kakwa/Cutbank 3,330 5,750 (42%)
Other 1,760 920 91%
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Total 23,780 21,500 11%
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>>
Over the past year, production in the Northern areas, Kakwa and Cutbank,
has declined significantly resulting in a more stable producing base. The
production decline in the Northern areas has masked the amount of production
growth that we have achieved in the greater Sundance area.
Currently, 4 drilling rigs are active in our core areas of Wildhay,
Sundance and Nosehill. Construction of the new Nosehill Gas Plant commenced in
July with startup expected in early September. This new 100% Peyto owned and
operated facility will provide processing capacity for the continued
development of gas reserves on the east side of the greater Sundance area.
Marketing
Peyto's marketing strategy, meant to be methodical and consistent, is
designed to smooth out short term fluctuations in the price of both natural
gas and natural gas liquids through future sales. Although second quarter
natural gas prices were 16% lower than Q2 2005 and 30% lower than Q1 2006,
Peyto's realized gas price, after hedging, was effectively the same as the
second quarter 2005, and only 14% lower than the first quarter of 2006.
Forward sales for the second quarter of 2006 increased Peyto's combined
gas and liquids price by $5.32/boe, which resulted in a gain of $11.1 million.
As of June 30, 2006, Peyto had committed to the forward sale of 211,000
barrels of crude oil at an average price of $76.62 per barrel and 21,160,000
gigajoules (GJ) of natural gas at an average price of $8.93 per GJ. Peyto's
current forward sale volume for 2006 represents approximately 60% of current
gas production net of royalties and 40% of 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 $10.45, which is 31% higher than the
price Peyto realized in the second quarter of 2006. This forward price
averaging gives stability to both the monthly distributions and capital
expenditure program.
Management Succession
Don Gray, the Founder, President and Chief Executive Officer of Peyto,
has announced his intention to step back from day to day involvement with
Peyto. Darren Gee, Peyto's VP Engineering, will advance to the role of
President. Don Gray will continue as the Chief Executive Officer until January
1, 2007, at which time Mr. Gee will assume the role of President and Chief
Executive Officer. In addition, Scott Robinson, the current VP Operations,
will assume the role of Executive VP and Chief Operating Officer. Mr. Gray
will remain an active Director of Peyto, allowing him to contribute his
perspective to both strategy and operations.
On behalf of all unitholders, the Board would like to thank Don for his
leadership of Peyto. In commenting on the succession, Mr. Mottershead,
Chairman of the Board said, "Over the past eight years Don's vision,
leadership and empowerment of people has built a company known for its
technical expertise and superior assets. I believe these attributes will allow
Peyto to seamlessly transition to its next CEO."
Don Gray said, "It has truly been an honor to lead such an incredible
company. When we embarked on this journey eight years ago we faced many
hurdles. Today Peyto is known for having the best assets and the strongest
business model in the trust sector. I take a lot of pride in knowing that we
have not only built great assets but we have also empowered future leaders.
I'm confident and excited about Peyto's future."
Outlook
As the Peyto team continues to put more producing assets into the
"reserve bank", the resources that fund our growing distributions and capital
program continue to increase. In light of the higher service costs and lower
summer gas prices we believe it is appropriate to temporarily slow down our
pace of development. For the balance of 2006, we intend to "live within our
means", utilizing cash flow after distributions and available bank lines to
fund our capital program. The majority of our capital program will be focused
on opportunities that can be quickly converted into proven producing reserves,
production and cash flow. Visit the Peyto website at www.peyto.com where you
will find a wealth of information designed to inform and educate investors.
Conference Call and Webcast
A conference call will be held with the senior management of Peyto to
answer questions with respect to the 2006 second quarter results on Thursday,
August 10, 2006 at 9:00 a.m. Mountain Standard Time (MST), 11:00 a.m. Eastern
Standard Time (EST). To participate, please call 1-416-644-3416 (Toronto area)
or 1-800-796-7558 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 21194285 followed by the pound key. The
replay will be available at 11:00 a.m. MST, 1:00 p.m. EST Thursday, August 10
2006 until midnight EST on Thursday, August 17, 2006. The conference call can
also be accessed through the internet at
http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID(equal sign)1518220.
<<
Don T. Gray Darren Gee
Chief Executive Officer President
August 9, 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 Peyto will derive therefrom. Peyto disclaims
any intention or obligation to update or revise any forward-looking
statements, whether as a result of new information, future events or
otherwise.
Management's discussion and analysis
This Management's Discussion and Analysis ("MD&A") should be read in
conjunction with the unaudited interim consolidated financial statements for
the period ended June 30, 2006 and the audited consolidated financial
statements of Peyto Energy Trust ("Peyto" or the "Trust") for the year ended
December 31, 2005. The consolidated financial statements have been prepared in
accordance with Canadian generally accepted accounting principles ("GAAP").
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).
To the best of our knowledge, Peyto's foreign ownership level currently
stands at approximately 26 percent, well below the level that would jeopardize
Peyto's status as a mutual fund trust under current or proposed legislation.
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.
QUARTERLY FINANCIAL INFORMATION
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2006 2005 2004
($000 except per
unit amounts) Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3
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Total revenue
(net of
royalties) 88,515 86,459 94,111 84,912 73,473 72,397 66,024 59,337
Funds from
operations 77,507 78,617 86,607 77,179 66,548 66,636 60,334 54,211
Per unit -
basic(x) 0.74 0.76 0.85 0.78 0.69 0.69 0.65 0.60
Per unit -
diluted(x) 0.74 0.76 0.85 0.78 0.69 0.69 0.65 0.60
Earnings (loss) 56,768 45,293 60,745 37,702 25,690 37,431 (2,558)21,650
Per unit -
basic(x) 0.54 0.44 0.60 0.38 0.27 0.39 (0.03) 0.24
Per unit -
diluted(x) 0.54 0.44 0.60 0.38 0.27 0.39 (0.03) 0.24
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(x) Note: prior periods restated for 2 for 1 split of trust units
completed May 31, 2005.
RESULTS OF OPERATIONS
Production
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Three Months ended Six Months ended
June 30 June 30
2006 2005 2006 2005
-------------------------------------------------------------------------
Natural gas (mmcf/d) 112.5 106.9 111.7 104.9
Oil & natural gas liquids (bbl/d) 4,145 4,653 4,144 4,495
Barrels of oil equivalent (boe/d) 22,892 22,464 22,758 21,990
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Natural gas production averaged 112.5 mmcf/d in the second quarter of
2006, 5 percent higher than the 106.9 mmcf/d reported for the same period in
2005. Oil and natural gas liquids production averaged 4,145 bbl/d, a decrease
of 11 percent from 4,653 bbl/d reported in the prior year. First half
production increased 3 percent from 21,990 boe/d to 22,758 boe/d. The overall
production increases are directly attributable to Peyto's ongoing drilling
program offsetting natural production declines.
Commodity Prices
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Three Months ended Six Months ended
June 30 June 30
2006 2005 2006 2005
-------------------------------------------------------------------------
Natural gas ($/mcf) 6.80 8.14 8.22 7.80
Hedging - gas ($/mcf) 1.16 (0.13) 0.38 0.11
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Natural gas - after hedging ($/mcf) 7.96 8.00 8.60 7.91
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Oil and natural gas liquids($/bbl) 69.03 54.88 65.42 56.29
Hedging - oil ($/bbl) (2.09) (3.85) (3.36) (3.11)
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Oil and natural gas liquids -
after hedging ($/bbl) 66.94 51.03 62.06 53.18
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Total Hedging ($/boe) 5.32 (1.44) 1.27 0.12
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Our natural gas price before hedging averaged $6.80/mcf during the second
quarter of 2006, a decrease of 17 percent from $8.14/mcf reported for the
equivalent period in 2005. Oil and natural gas liquids prices averaged
$69.03/bbl up 26 percent from $54.88/bbl a year earlier. Hedging activity for
the second quarter of 2006 accounted for $5.32/boe of Peyto's price achieved.
Expectations are for commodity prices to remain strong relative to historical
pricing.
Revenue
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Three Months ended Six Months ended
June 30 June 30
($000) 2006 2005 2006 2005
-------------------------------------------------------------------------
Natural gas 69,634 79,130 166,153 147,206
Oil and natural gas liquids 26,036 23,236 49,064 45,803
Hedging gain (loss) 11,081 (2,939) 5,251 487
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Total revenue 106,751 99,427 220,468 193,496
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For the three months ended June 30, 2006, gross revenue increased 7
percent to $106.7 million from $99.4 million for the same period in 2005. The
increase in revenue for the period was a result of stronger commodity prices
for liquids, our hedging program and increased production volumes for natural
gas, as detailed in the following table:
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Three Months ended June 30
2006 2005 Change $million
-------------------------------------------------------------------------
Natural gas
Volume (mcf/d) 112,484 106,866 5,618
Volume (mmcf) 10,236 9,725 511 4
Price ($/mcf) $7.96 $8.00 $(0.04) (1)
Oil & NGL
Volume (bbl/d) 4,145 4,653 (508)
Volume (mbbl) 377 423 (46) (2)
Price ($/bbl) $66.94 $51.03 $15.91 7
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Total revenue ($million) 107 99 8 8
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Six Months ended June 30
2006 2005 Change $million
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Natural gas
Volume (mcf/d) 111,685 104,965 6,720
Volume (mmcf) 20,215 18,999 1,216 10
Price ($/mcf) $8.60 $7.91 $0.69 13
Oil & NGL
Volume (bbl/d) 4,144 4,496 (352)
Volume (mbbl) 750 813 (63) (3)
Price ($/bbl) $62.06 $53.18 $8.88 7
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Total revenue ($million) 220 193 27 27
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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.
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Three Months ended Six Months ended
June 30 June 30
2006 2005 2006 2005
-------------------------------------------------------------------------
Royalties, net of ARTC ($000) 18,236 25,954 45,494 47,626
% of sales 17 26 21 25
$/boe 8.75 12.69 10.47 11.19
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For the second quarter of 2006, royalties averaged $8.75/boe or
approximately 17 percent of Peyto's total petroleum and natural gas sales. The
royalty rate expressed as a percentage of sales, will fluctuate from period to
period due to the fact that the Alberta Reference Price can differ
significantly from the commodity prices obtained by the Trust. In addition,
royalties paid in the second quarter of 2006 were reduced by a larger than
anticipated annual adjustment to the 2005 Gas Cost Allowance while sales where
increased by a significant realized hedging gain of $11.1 million. It is
management's expectation that royalties as a percentage of sales for future
periods will remain at historical levels.
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.
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Three Months ended Six Months ended
June 30 June 30
2006 2005 2006 2005
-------------------------------------------------------------------------
Operating costs ($000)
Field expenses 6,252 4,235 11,260 8,061
Processing and gathering income (1,546) (1,583) (2,878) (3,045)
-------------------------------------------------------------------------
Total operating costs 4,706 2,652 8,382 5,016
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$/boe 2.26 1.30 2.03 1.26
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Transportation 1,237 1,387 2,511 2,703
-------------------------------------------------------------------------
$/boe 0.59 0.68 0.61 0.68
-------------------------------------------------------------------------
Operating costs were $4.7 million in the second quarter of 2006 compared
to $2.6 million during the same period a year earlier. On a unit of production
basis, operating costs averaged $2.26/boe in the second quarter of 2006
compared to $1.30/boe for the second quarter of 2005. The increased cost is
attributable to both year-over-year inflationary effects as well as new
infrastructure related costs associated with the new Wildhay plant.
Furthermore, the producing well count has increased over the year adding
additional fixed costs.
Netbacks
Operating netbacks represent the profit margin associated with the
production and sale of petroleum and natural gas. The primary factors that
produce Peyto's strong netbacks are a low cost structure and the high heat
content of our natural gas that results in higher commodity prices.
-------------------------------------------------------------------------
Three Months ended Six Months ended
June 30 June 30
($/boe) 2006 2005 2006 2005
-------------------------------------------------------------------------
Sale Price 51.24 48.64 53.50 47.84
Less:
Royalties 8.75 12.69 10.47 11.97
Operating costs 2.26 1.30 2.03 1.26
Transportation 0.59 0.68 0.61 0.68
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Operating netback 39.64 33.97 40.39 34.71
General and administrative 0.43 0.10 0.25 0.08
Interest on long-term debt 2.00 1.25 1.69 1.11
Capital tax - 0.06 - 0.06
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Cash netback 37.21 32.56 38.45 33.46
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General and Administrative Expenses
-------------------------------------------------------------------------
Three Months ended Six Months ended
June 30 June 30
2006 2005 2006 2005
-------------------------------------------------------------------------
G&A expenses ($000) 2,362 1,529 4,415 2,940
Overhead recoveries (1,473) (1,320) (3,400) (2,620)
-------------------------------------------------------------------------
Net G&A expenses 889 209 1,015 320
-------------------------------------------------------------------------
$/boe 0.43 0.10 0.25 0.08
-------------------------------------------------------------------------
General and administrative expenses before overhead recoveries increased
to $2.4 million in the second quarter of 2006, as compared to $1.5 million for
the same period in 2005 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 $0.43 per boe. Our capital program was
reduced quarter over quarter, causing related overhead recoveries to decline.
Interest Expense
-------------------------------------------------------------------------
Three Months ended Six Months ended
June 30 June 30
2006 2005 2006 2005
-------------------------------------------------------------------------
Interest expense ($000) 4,175 2,552 6,942 4,422
$/boe 2.00 1.25 1.69 1.11
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>>
Second quarter 2006 interest expense was $4.2 million or $2.00/boe
compared to $2.5 million or $1.25/boe a year earlier. During 2006, average
debt levels have increased to partially fund Peyto's capital expenditure
program. Interest rates continue to be favourable and are not expected to
increase substantially in the short term.
Depletion, Depreciation and Accretion
The 2006 second quarter provision for depletion, depreciation and
accretion totaled $20.5 million as compared to $14.5 million in 2005. On a
unit of production basis, depletion, depreciation and accretion costs averaged
$9.86/boe as compared to $7.08/boe in 2005. The increase in the provision for
depletion, depreciation and accretion costs is attributable to the increased
cost of finding and developing new reserves.
Income Taxes
The current provision for future income tax decreased to $11.6 million
for the first half of 2006 from $17.7 million for the same period in 2005.
This decrease is primarily due to increased capital activity year over year
generating higher tax pools and to reflect the reduction in federal and
provincial income tax rates being phased in over the next four years.
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 the second quarter of 2006, we recorded a hedging gain of $11.1
million as compared to a hedging loss of $2.7 million in the second quarter of
2005. As set out under the section "Critical Accounting Estimates", we
adopted, effective January 1, 2004, the CICA Accounting Guideline 13 with
respect to Hedging Relationships. A summary of contracts outstanding in
respect of the hedging activities are as follows:
<<
Crude Oil Daily
Period Hedged Type Volume Price (CAD)
-------------------------------------------------------------------------
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
July 1 to September 30, 2006 Fixed price 200 bbl $80.20/bbl
August 1 to September 30, 2006 Fixed price 100 bbl $85.75/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
October 1 to December 31, 2006 Fixed price 200 bbl $81.10/bbl
October 1 to December 31, 2006 Fixed price 200 bbl $87.10/bbl
October 1 to December 31, 2006 Fixed price 200 bbl $87.13/bbl
January 1 to March 31, 2007 Fixed price 200 bbl $82.82/bbl
January 1 to March 31, 2007 Fixed price 200 bbl $87.35/bbl
January 1 to March 31, 2007 Fixed price 200 bbl $88.00/bbl
April 1 to June 30, 2007 Fixed price 200 bbl $82.39/bbl
April 1 to June 30, 2007 Fixed price 200 bbl $87.10/bbl
April 1 to June 30, 2007 Fixed price 200 bbl $88.05/bbl
July 1 to September 30, 2007 Fixed price 200 bbl $87.61/bbl
July 1 to September 30, 2007 Fixed price 200 bbl $88.20/bbl
Natural Gas Daily
Period Hedged Type Volume Price (CAD)
-------------------------------------------------------------------------
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
July 1 to October 31, 2006 Fixed price 5,000 GJ $6.53/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $8.71/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $9.00/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $9.05/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $10.06/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $10.28/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $11.40/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $11.60/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $9.65/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $10.25/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $9.00/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $8.65/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $9.23/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $8.60/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $7.50/GJ
Apr. 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $8.90/GJ
>>
Commodity Price Sensitivity
Our low operating costs, low distribution ratio, marketing program and
long reserve life reduce our sensitivity to changes in commodity prices.
Currency Risk Management
The Trust is exposed to fluctuations in the Canadian/US dollar exchange
ratio since our natural gas and oil sales are effectively priced in US dollars
and converted to Canadian dollars. In the short term, this risk is mitigated
indirectly as a result of our commodity hedging strategy as we hedge at
Canadian prices. Over the long term, the Canadian dollar tends to rise as oil
prices rise. There is a similar correlation between oil and gas prices.
Currently we have not entered into any agreements to further manage this
specific risk.
Interest Rate Risk Management
The Trust is exposed to interest rate risk in relation to interest
expense on its revolving demand facility. Currently we have not entered into
any agreements to manage this risk. At June 30, 2006, the increase or decrease
in earnings for each 100 bps change in interest rate paid on the outstanding
revolving demand loan amounts to approximately $3.2 million per annum.
<<
LIQUIDITY AND CAPITAL RESOURCES
Funds from Operations
-------------------------------------------------------------------------
Three Months ended Six Months ended
June 30 June 30
($000) 2006 2005 2006 2005
-------------------------------------------------------------------------
Net earnings 56,768 25,690 102,061 63,121
Items not requiring cash:
Non-cash provision for
performance based compensation (2,626) 21,118 2,196 25,045
Future income tax expense 2,878 5,261 11,555 17,730
Depletion, depreciation &
accretion 20,487 14,479 40,312 27,288
-------------------------------------------------------------------------
Funds from operations 77,507 66,548 156,124 133,184
-------------------------------------------------------------------------
>>
For the three months ended June 30, 2006, funds from operations totaled
$77.5 million or $0.74 per unit, representing a 16 percent increase from the
$66.5 million, or $0.69 per unit during the same period in 2005. Peyto's
policy is to distribute approximately 50% of funds from operations to
unitholders while retaining the balance to fund its growth oriented capital
expenditures program. Our earnings and cash flow are sensitive to changes in
commodity prices, exchange rates and other factors that are beyond our
control. Current volatility in commodity prices creates uncertainty as to our
funds from operations and capital expenditure budget. Accordingly, we assess
results throughout the year and revise our operational plans as necessary to
reflect the most current information.
Our revenues will be impacted by drilling success and production volumes
as well as external factors such as the market prices for natural gas and
crude oil and the exchange rate of the Canadian dollar relative to the US
dollar.
Bank Debt
We have an extendible revolving term credit facility with a syndicate of
financial institutions in the amount of $450 million which includes a
$430 million revolving facility and a $20 million operating facility.
Available borrowings are limited by a borrowing base, which is based on the
value of petroleum and natural gas assets as determined by the lenders. The
loan is reviewed annually and may be extended at the option of the lender for
an additional 364 day period. If not extended, the revolving facility will
automatically convert to a one year and one day non revolving term loan. The
loan has therefore been classified as long term on the balance sheet. The
average borrowing rate for the second quarter of 2006 was 4.41% (2005 -
4.04%).
At June 30, 2006, $390 million was drawn under the facility. Working
capital liquidity is maintained by drawing from and repaying the unutilized
credit facility as needed. At June 30, 2006, we had a working capital deficit
of $21.1 million.
We believe that funds generated from our operations, together with
borrowings under our credit facility and proceeds from equity issued through
our DRIP and Optional Trust Unit Purchase Plan will be sufficient to finance
our current operations and planned capital expenditure program. 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. 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.
Subsequent to June 30, 2006 60,819 trust units (58,018 pursuant to the
DRIP and 2,801 pursuant to the OTUPP) were issued for net proceeds of
$1.4 million. Subsequent to the issuance of these units, 104,710,005 trust
units were outstanding (June 30, 2006 - 104,649,186).
<<
Authorized: Unlimited number of voting trust units
Issued and Outstanding:
Number of Amount
Trust Units (no par value) Shares/Units $
-------------------------------------------------------------------------
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
Trust units issued by private placement 1,393,940 34,378,613
Trust units issued pursuant to DRIP 490,563 11,903,158
Trust units issued pursuant to OTUPP 430,836 10,207,682
-------------------------------------------------------------------------
Balance, June 30, 2006 104,649,186 385,225,363
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
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%. This methodology
can generate interim results which vary significantly from the final
compensation paid. No provision for the reserve value based component was
recorded for the second quarter of 2006.
Under the market based component, rights with a three year vesting period
are allocated to employees and key consultants. The number of rights
outstanding at any time is not to exceed 6% of the total number of trust units
outstanding. At December 31 of each year, all vested rights are automatically
cancelled and, if applicable, paid out in cash. Compensation is calculated as
the number of vested rights multiplied by the total of the market appreciation
(over the price at the date of grant) and associated distributions of a trust
unit for that period. A tax factor of 1.333 is then applied to determine the
amount to be paid.
Based on the five day weighted average trading price of the trust units
for the period ended June 30, 2006, compensation costs related to 4.5 million
non-vested rights, with an average grant price of $22.84, total $2.2 million.
The Trust records a non-cash provision for future compensation expense over
the life of the rights. The cumulative provision totals $12.3 million of which
a recovery of $2.6 million was recorded in the three months ending June 30,
2006.
Capital Expenditures
Net capital expenditures for the second quarter of 2006 totaled
$67.2 million. Exploration and development related activity represented
$52.3 million or 78% of the total, while expenditures on facilities, gathering
systems and equipment totaled $10.3 million or 15% of the total. The following
table summarizes capital expenditures for the quarter.
<<
-------------------------------------------------------------------------
Three Months ended Six Months ended
June 30 June 30
($000) 2006 2005 2006 2005
-------------------------------------------------------------------------
Land 2,047 2,916 12,678 5,292
Seismic 2,434 1,507 7,571 2,502
Drilling - Exploratory &
Development 52,330 46,369 153,317 119,896
Production Equipment,
Facilities & Pipelines 10,332 7,910 38,574 30,094
Acquisitions & Dispositions - - - -
Office Equipment 52 28 149 21
-------------------------------------------------------------------------
Total Capital Expenditures 67,195 58,730 212,289 157,805
-------------------------------------------------------------------------
Distributions
-------------------------------------------------------------------------
Three Months ended Six Months ended
June 30 June 30
2006 2005 2006 2005
-------------------------------------------------------------------------
Funds from operations ($000) 77,507 66,548 156,124 133,184
Total distributions ($000) 43,921 33,898 85,439 64,370
Total distributions per
unit ($)(x) 0.42 0.35 0.82 0.665
Payout ratio (%) 57 51 55 48
Cash distributions ($000)
(net of DRIP) 38,315 31,023 72,980 61,005
Payout ratio (%) 49 47 47 46
-------------------------------------------------------------------------
>>
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. As participation in the DRIP is
optional and fluctuates monthly, the payout ratio of 50 percent is based on
total distributions including those settled in units pursuant to the DRIP. The
Board 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 476,742
2007 953,484
2008 1,096,641
2009 1,096,641
2010 1,096,641
2011 1,096,641
-------------------------------------------------------------------------
5,816,790
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
GUARANTEES/OFF BALANCE SHEET ARRANGEMENTS
The Trust is a party to certain off balance sheet derivative financial
instruments, including fixed price contracts as discussed further in the
Hedging section.
RELATED PARTY TRANSACTIONS
During the first quarter of 2006, the Trust paid $620,218 to a company
with a director who was also a director of the Trust until May 16, 2006. This
payment related to a joint venture capital project.
An officer of the Trust is a partner of a law firm that provides legal
services to the Trust. The fees charged are based on standard rates and time
spent on matters pertaining to the Trust and its subsidiaries. For the first
six months of 2006, the accrued and actual legal fees totaled $181,445.
INCOME TAXES
The following sets out a general discussion of the Canadian and US tax
consequences of holding Peyto units as capital property. The summary is not
exhaustive in nature and is not intended to provide legal or tax advice.
Unitholders or potential Unitholders should consult their own legal or tax
advisors as to their particular tax consequences.
Canadian Taxpayers
The Trust qualifies as a mutual fund trust under the Income Tax Act
(Canada) and, accordingly, Trust units are qualified investments for RRSPs,
RRIFs, RESPs and DPSPs. Each year, the Trust is required to file an income tax
return and any taxable income of the Trust is allocated to unitholders.
Unitholders are required to include in computing income their pro rata
share of any taxable income earned by the Trust in that year. An investor's
adjusted cost base (ACB) in a trust unit equals the purchase price of the unit
less any non taxable cash distributions received from the date of acquisition.
To the extent the unitholders' ACB is reduced below zero, such amount will be
deemed to be a capital gain to the unitholder and the unitholders' ACB will be
brought to nil.
During the first half of 2006, the Trust paid distributions to the
unitholders in the amount of $85.4 million (2005 - $64.4 million) in
accordance with the following schedule:
<<
Production Period Record Date Distribution Date Per Unit
-------------------------------------------------------------------------
January 2006 January 31, 2006 February 15, 2006 $0.12
February 2006 February 28, 2006 March 15, 2006 $0.14
March 2006 March 31, 2006 April 13, 2006 $0.14
April 2006 April 30, 2006 May 15, 2006 $0.14
May 2006 May 31, 2006 June 15, 2006 $0.14
June 2006 June 30, 2006 July 14, 2006 $0.14
>>
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
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 2005 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
-----------------------------------------------
2006
Q2 Q1
-----------------------------------------------
Operations
Production
Natural gas
(mcf/d) 112,484 110,878
Oil & NGLs (bbl/d) 4,145 4,143
Barrels of oil
equivalent
(boe/d at 6:1) 22,892 22,622
Average product prices
Natural gas ($/mcf) 7.96 9.26
Oil & natural gas
liquids ($/bbl) 66.94 57.12
Average operating
expenses ($/boe) 2.26 1.81
Average transportation
costs ($/boe) 0.59 0.63
Field netback ($/boe) 39.64 40.02
General &
administrative expense
($/boe) 0.43 0.06
Interest expense
($/boe) 2.00 1.36
Financial ($000
except per unit)
Revenue 106,751 113,717
Royalties
(net of ARTC) 18,236 27,258
Funds from operations 77,507 78,617
Funds from
operations per
unit(x) 0.74 0.76
Total distributions 43,921 41,517
Total distributions
per unit(x) 0.42 0.40
Payout ratio 57% 53%
Cash distributions
(net of DRIP) 38,315 34,665
Payout ratio 49% 44%
Earnings 56,768 45,293
Earnings per
diluted unit(x) 0.54 0.44
Capital expenditures 67,195 145,094
Weighted average
trust units
outstanding(x) 104,472,570 103,910,640
-------------------------------------------------------------------------
2005
Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Operations
Production
Natural gas
(mcf/d) 108,356 108,460 106,866 103,043
Oil & NGLs (bbl/d) 4,185 4,569 4,653 4,337
Barrels of oil
equivalent
(boe/d at 6:1) 22,245 22,646 22,464 21,511
Average product prices
Natural gas ($/mcf) 10.55 8.67 8.00 7.81
Oil & natural gas
liquids ($/bbl) 58.43 57.22 51.03 55.52
Average operating
expenses ($/boe) 1.95 1.70 1.30 1.22
Average transportation
costs ($/boe) 0.70 0.66 0.68 0.68
Field netback ($/boe) 43.33 38.39 33.97 35.50
General &
administrative expense
($/boe) 0.05 0.13 0.10 0.06
Interest expense
($/boe) 0.91 1.16 1.25 0.97
Financial ($000
except per unit)
Revenue 127,633 110,566 99,427 94,069
Royalties
(net of ARTC) 33,522 25,654 25,954 21,672
Funds from operations 86,607 77,179 66,548 66,636
Funds from
operations per
unit(x) 0.85 0.78 0.69 0.69
Total distributions 36,773 35,505 33,898 30,472
Total distributions
per unit(x) 0.36 0.36 0.35 0.315
Payout ratio 42% 46% 51% 46%
Cash distributions
(net of DRIP) 33,771 32,318 31,023 29,982
Payout ratio 39% 42% 47% 45%
Earnings 60,745 37,702 25,690 37,431
Earnings per
diluted unit(x) 0.60 0.38 0.27 0.39
Capital expenditures 107,647 93,001 58,730 99,074
Weighted average
trust units
outstanding(x) 102,148,411 98,584,597 96,848,988 96,664,210
(x) Note: prior periods restated for 2 for 1 split of trust units
completed May 31, 2005.
Peyto Energy Trust
Consolidated Balance Sheets
(unaudited)
June 30, December 31,
2006 2005
$ $
-------------------------------------------------------------------------
Assets
Current
Cash 3,839,181 -
Accounts receivable (Note 4) 57,800,266 82,793,463
Due from private placements - 27,450,247
Prepaid expenses and deposits 6,207,115 1,795,540
-------------------------------------------------------------------------
67,846,562 112,039,250
Property, plant and equipment (Note 2) 1,005,491,420 832,887,287
-------------------------------------------------------------------------
1,073,337,982 944,926,537
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities and Unitholders' Equity
Current
Accounts payable and accrued liabilities 64,354,041 208,284,019
Capital taxes payable 110,412 110,412
Cash distributions payable 13,345,463 11,529,973
Provision for future performance based
compensation 11,118,639 8,748,198
-------------------------------------------------------------------------
88,928,555 228,672,602
-------------------------------------------------------------------------
Long-term debt (Note 3) 390,000,000 180,000,000
Provision for future performance based
compensation 1,227,007 1,400,970
Asset retirement obligations 5,355,379 4,729,098
Future income taxes 119,848,622 108,292,966
-------------------------------------------------------------------------
516,431,008 294,423,034
-------------------------------------------------------------------------
Unitholders' equity
Unitholders' capital (Note 4) 385,225,363 328,735,910
Units to be issued (Note 4) 1,368,438 28,332,345
Accumulated earnings 437,986,515 335,925,837
Accumulated distributions (Note 5) (356,601,897) (271,163,191)
-------------------------------------------------------------------------
467,978,419 421,830,901
-------------------------------------------------------------------------
1,073,337,982 944,926,537
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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
(unaudited)
Three Months Ended Six Months Ended
June 30 June 30
2006 2005 2006 2005
$ $ $ $
-------------------------------------------------------------------------
Revenue
Petroleum and
natural gas
sales, net 88,514,997 73,472,840 174,974,213 145,869,788
-------------------------------------------------------------------------
Expenses
Operating (Note 6) 4,705,710 2,652,209 8,381,676 5,015,582
Transportation 1,237,147 1,386,829 2,510,980 2,702,996
General and
administrative
(Note 7) 889,272 209,031 1,015,205 319,674
Future market and
reserves based
bonus provision (2,625,718) 21,117,684 2,196,478 25,044,723
Interest 4,175,384 2,551,745 6,941,964 4,422,402
Depletion,
depreciation
and accretion
(Note 2) 20,487,037 14,479,191 40,311,576 27,288,487
-------------------------------------------------------------------------
28,868,832 42,396,689 61,357,879 64,793,864
-------------------------------------------------------------------------
Earnings before
taxes 59,646,165 31,076,151 113,616,334 81,075,924
-------------------------------------------------------------------------
Taxes
Future income
tax expense 2,878,656 5,260,992 11,555,656 17,729,992
Capital tax expense - 125,000 - 225,000
-------------------------------------------------------------------------
2,878,656 5,385,992 11,555,656 17,954,992
-------------------------------------------------------------------------
Net earnings for
the period 56,767,509 25,690,159 102,060,678 63,120,932
Accumulated
earnings,
beginning of
period 381,219,006 211,788,866 335,925,837 174,358,093
-------------------------------------------------------------------------
Accumulated
earnings,
end of period 437,986,515 237,479,025 437,986,515 237,479,025
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per
unit (Note 4)
Basic 0.54 0.27 0.98 0.65
Diluted 0.54 0.27 0.98 0.65
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
Peyto Energy Trust
Consolidated Statements of Cash Flows
(unaudited)
Three Months Ended Six Months Ended
June 30 June 30
2006 2005 2006 2005
$ $ $ $
-------------------------------------------------------------------------
Cash provided by
(used in)
Operating Activities
Net earnings
for the period 56,767,509 25,690,159 102,060,678 63,120,932
Items not requiring
cash:
Future income
tax expense 2,878,656 5,260,992 11,555,656 17,729,992
Depletion,
depreciation
and accretion 20,487,037 14,479,191 40,311,576 27,288,487
Change in non-cash
working capital
related to
operating
activities 2,267,844 10,854,377 27,534,260 1,153,941
-------------------------------------------------------------------------
82,401,046 56,284,719 181,462,170 109,293,352
-------------------------------------------------------------------------
Financing Activities
Issue of trust
units, net of
costs and DRIP 112,015 - 17,067,064 4,430,515
Cash distributions
paid (net
of DRIP) (38,315,010) (31,022,916) (72,980,224) (61,005,127)
Increase in
bank debt 90,000,000 70,000,000 210,000,000 100,000,000
Change in non-cash
working capital
related to
financing
activities 9,610,088 470,546 29,265,737 28,639,566
-------------------------------------------------------------------------
61,407,093 39,447,630 183,352,577 72,064,954
-------------------------------------------------------------------------
Investing Activities
Additions to
property, plant
and equipment (67,195,003) (58,730,387) (212,289,431) (157,804,797)
Change in non-cash
working capital
related to
investing
activities (72,773,955) (30,585,401) (148,686,135) (17,136,948)
-------------------------------------------------------------------------
(139,968,958) (89,315,788) (360,975,566) (174,941,745)
-------------------------------------------------------------------------
Net increase
(decrease)
in cash 3,839,181 6,416,561 3,839,181 6,416,561
Cash, beginning
of period - - - -
-------------------------------------------------------------------------
Cash, end of period 3,839,181 6,416,561 3,839,181 6,416,561
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Peyto Energy Trust
Notes to Consolidated Financial Statements
(unaudited)
June 30, 2006 and 2005
1. Summary of Significant Accounting Policies
The unaudited interim consolidated financial statements of Peyto
Energy Trust (the "Trust") follow the same accounting policies as the
most recent annual audited financial statements. The interim
consolidated financial statement note disclosures do not include all
of those required by Canadian generally accepted accounting
principles applicable for annual financial statements. Accordingly,
these interim financial statements should be read in conjunction with
the 2005 audited consolidated financial statements.
These financial statements include the accounts of Peyto Energy Trust
and its wholly owned subsidiaries, Peyto Exploration & Development
Corp. and Peyto Operating Trust.
Certain comparative figures have been reclassified to ensure
consistency with current period presentation.
2. Property, Plant and Equipment
June 30, December 31,
2006 2005
$ $
---------------------------------------------------------------------
Property, plant and equipment 1,188,749,944 976,005,103
Accumulated depletion and depreciation (183,258,524) (143,117,816)
---------------------------------------------------------------------
1,005,491,420 832,887,287
---------------------------------------------------------------------
---------------------------------------------------------------------
At June 30, 2006 costs of $39,529,264 (June 30, 2005 - $28,663,020)
related to undeveloped land have been excluded from the depletion and
depreciation calculation.
3. Long-Term Debt
The Trust has a syndicated $450 million extendible revolving credit
facility. The facility is made up of a $20 million working capital
sub-tranche and a $430 million production line. The facilities are
available on a revolving basis for a period of at least 364 days and
upon the term out date may be extended for a further 364 day period
at the request of the Trust, subject to approval by the lenders. In
the event that the revolving period is not extended, the facility is
available on a non-revolving basis for a one year term, at the end of
which time the facility would be due and payable. Outstanding amounts
on this facility bear interest at rates determined by the Trust's
debt to cash flow ratio that range from prime to prime plus 0.75% for
debt to 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.
4. 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, 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
Trust units issued by private placement 1,393,940 34,378,613
Trust units issued pursuant to DRIP 490,563 11,903,158
Trust units issued pursuant to OTUPP 430,836 10,207,682
---------------------------------------------------------------------
Balance, June 30, 2006 104,649,186 385,225,363
---------------------------------------------------------------------
---------------------------------------------------------------------
Units to be Issued
On March 2, 2005, Peyto implemented a Distribution Reinvestment Plan
("DRIP"). On November 21, 2005 the DRIP plan was amended to
incorporate an Optional Trust Unit Purchase Plan ("OTUPP") which
provides unitholders enrolled in the DRIP with the opportunity to
purchase additional trust units from treasury subject to certain
limitations, using the same pricing as the DRIP. On July 14, 2006, at
a price of $22.50 per trust unit, 58,018 trust units were issued from
treasury pursuant to the DRIP, and 2,801 trust units were issued from
treasury pursuant to the OTUPP. $63,015 (December 31, 2005 -
$132,000) was included in accounts receivable for the funds due Peyto
under the OTUPP.
Per Unit Amounts
Earnings per unit have been calculated based upon the weighted
average number of units outstanding during the period of 104,472,570
(2005 - 96,848,988). There are no dilutive instruments outstanding.
5. Accumulated 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 and
the Board are prepared to adjust the payout levels to balance desired
distributions with our requirement to maintain an appropriate capital
structure. During the quarter, the Trust paid total distributions to
the unitholders in the aggregate amount of $43.9 million of which
$38.3 million was settled in cash and $5.6 million was settled by the
issuance of trust units pursuant to the DRIP (2005 - total
$33.9 million; cash $31 million and DRIP $2.9 million) in accordance
with the following schedule:
Production Period Record Date Distribution Date Per Unit
---------------------------------------------------------------------
January 2006 January 31, 2006 February 15, 2006 $0.12
February 2006 February 28, 2006 March 15, 2006 $0.14
March 2006 March 31, 2006 April 13, 2006 $0.14
April 2006 April 30, 2006 May 15, 2006 $0.14
May 2006 May 31, 2006 June 15, 2006 $0.14
June 2006 June 30, 2006 July 14, 2006 $0.14
6. Operating Expenses
The Trust's operating expenses include all costs with respect to day-
to-day well and facility operations. Processing and gathering income
related to joint venture and third party natural gas reduces
operating expenses.
Three Months Ended Six Months Ended
June 30 June 30
2006 2005 2006 2005
$ $ $ $
---------------------------------------------------------------------
Field expenses 6,251,633 4,235,214 11,260,132 8,060,981
Processing and
gathering income (1,545,923) (1,583,005) (2,878,456) (3,045,399)
---------------------------------------------------------------------
Total operating
costs 4,705,710 2,652,209 8,381,676 5,015,582
---------------------------------------------------------------------
---------------------------------------------------------------------
7. General and Administrative Expenses
General and administrative expenses are reduced by operating and
capital overhead recoveries from operated properties.
Three Months Ended Six Months Ended
June 30 June 30
2006 2005 2006 2005
$ $ $ $
---------------------------------------------------------------------
G&A expenses 2,362,174 1,529,543 4,414,855 2,940,164
Overhead
recoveries (1,472,902) (1,320,512) (3,399,650) (2,620,490)
---------------------------------------------------------------------
Net G&A expenses 889,272 209,031 1,015,205 319,674
---------------------------------------------------------------------
8. 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
June 30, 2006 is as follows:
Weighted
Crude Oil Daily Average
Period Hedged Type Volume Price (CAD)
---------------------------------------------------------------------
July 1 to
September 30, 2006 Fixed price 1,100 bbl $75.55/bbl
October 1 to
December 31, 2006 Fixed price 800 bbl $75.15/bbl
January 1 to
March 31, 2007 Fixed price 200 bbl $82.82/bbl
April 1 to
June 30, 2007 Fixed price 200 bbl $82.39/bbl
Weighted
Natural Gas Daily Average
Period Hedged Type Volume Price (CAD)
---------------------------------------------------------------------
April 1 to
October 31, 2006 Fixed price 50,000 GJ $8.23/GJ
April 1, 2006 to
March 31, 2007 Fixed price 5,000 GJ $9.27/GJ
July 1 to
October 31, 2006 Fixed price 5,000 GJ $6.53/GJ
Nov. 1, 2006 to
March 31, 2007 Fixed price 60,000 GJ $9.74/GJ
April 1 to
October 31, 2007 Fixed price 10,000 GJ $8.05/GJ
April 1, 2007 to
March 31, 2008 Fixed price 5,000 GJ $8.90/GJ
As at June 30, 2006, the Trust had committed to the future sale of
211,000 barrels of crude oil at an average price of $76.62 per barrel
and 21,160,000 gigajoules (GJ) of natural gas at an average price of
$8.93 per GJ or $10.45 per mcf based on the historical heating value
of Peyto's natural gas. These contracts will generate revenue
totaling $205.2 million. Based on the market's estimate of the future
commodity prices as at June 30, 2006 the fair value of these
contracts would be $174.7 million.
Subsequent to June 30, 2006 the Trust entered into the following
contracts:
Crude Oil Daily
Period Hedged Type Volume Price (CAD)
---------------------------------------------------------------------
August 1 to
September 30, 2006 Fixed price 100 bbl $85.75/bbl
October 1 to
December 31, 2006 Fixed price 400 bbl $87.12/bbl
January 1 to
March 31, 2007 Fixed price 400 bbl $87.68/bbl
April 1 to
June 30, 2007 Fixed price 400 bbl $87.58/bbl
July 1 to
September 30, 2007 Fixed price 400 bbl $87.91/bbl
Fair Values of Financial Assets and Liabilities
The Trust's financial instruments include accounts receivable,
current liabilities, provision for future performance based
compensation and long term debt. At June 30, 2006, the carrying value
of accounts receivable, current liabilities and provision for future
performance based compensation approximate their value due to their
short term nature or method of determination. The carrying value of
the long term debt approximates its fair value due to the floating
rate of interest charged under the facilities.
Credit Risk
A substantial portion of the Trust's accounts receivable is with
petroleum and natural gas marketing entities. The Trust generally
extends unsecured credit to these companies, and therefore, the
collection of accounts receivable may be affected by changes in
economic or other conditions and may accordingly impact the Trust's
overall credit risk. Management believes the risk is mitigated by the
size, reputation and diversified nature of the companies to which
they extend credit. The Trust has not previously experienced any
material credit losses on the collection of accounts receivable. Of
the Trust's significant individual accounts receivable at June 30,
2006, approximately 50% was due from two companies (December 31,
2005 - 42%).
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 June 30, 2006, the
increase or decrease in earnings for each 1% change in interest rate
paid on the outstanding revolving demand loan amounts to
approximately $3.2 million per annum.
9. Supplemental Cash Flow Information
Three Months Ended Six Months Ended
June 30 June 30
2006 2005 2006 2005
$ $ $ $
---------------------------------------------------------------------
Cash interest paid 4,175,384 2,551,745 6,941,964 4,422,402
Cash taxes paid - 125,000 - 225,000
10. Contingencies and Commitments
a) Contingent Liability
From time to time, Peyto is the subject of litigation arising out
of Peyto's operations. Damages claimed pursuant to such litigation,
including the litigation discussed below, may be material or may be
indeterminate and the outcome of such litigation may materially
impact Peyto's financial condition or results of operations. While
Peyto assesses the merits of each lawsuit and defends itself
accordingly, Peyto may be required to incur significant expenses or
devote significant resources to defending itself against such
litigation. These claims are not currently expected to have a
material impact on Peyto's financial position.
Peyto has been named in a Statement of Claim issued by Canadian
Natural Resources Limited and affiliates ("CNRL"), claiming $13M in
damages for alleged breaches of duty as operator of jointly owned
properties, and an interim and permanent injunction to prevent Peyto
from proceeding with the completion of a well on those properties.
CNRL alleges that Peyto failed to take proper steps as operator of a
joint well (the "Well") on lands that offset 100% Peyto owned lands.
Peyto has filed a Statement of Defence defending the allegations set
forth in the Statement of Claim. The injunction claimed by CNRL was
to prevent Peyto from completing the Well at a target location which
had been agreed upon by both parties. Although claimed in the
Statement of Claim, CNRL did not apply for an interim injunction, and
Peyto completed the Well as planned, but no commercial production was
obtained. Accordingly, it remains to be seen whether CNRL will
proceed with the action. If the action goes ahead, Peyto intends to
defend itself vigorously. Although the outcome of this matter is not
determinable at this time, Peyto believes that this claim will not
have a material adverse effect on Peyto's financial position or
results of operations.
b) Commitments
The Trust is committed to payments under operating leases for office
space as follows:
$
---------------------------------------------------------------------
2006 476,742
2007 953,484
2008 1,096,641
2009 1,096,641
2010 1,096,641
2011 1,096,641
---------------------------------------------------------------------
5,816,790
---------------------------------------------------------------------
---------------------------------------------------------------------
11. Related Party Transactions
During the period ended March 31, 2006, the Trust paid $620,218 to a
company with a shareholder who was also a director of the Trust until
May 16, 2006, related to a joint venture capital project. Costs
associated with this joint venture capital project are billed and
paid in accordance with normal business operations.
An officer of the Trust is a partner of a law firm that provides
legal services to the Trust. The fees charged are based on standard
rates and time spent on matters pertaining to the Trust and its
subsidiaries. For the first half of 2006, legal fees totaled $181,445
(2005 - $49,988).
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, Chairman
Rick Braund
Don Gray
Brian Craig
John Boyd
Michael MacBean
Auditors
Deloitte & TouchDe LLP
Solicitors
Burnet, Duckworth & Palmer LLP
Bankers
Bank of Montreal
Union Bank of California
Royal Bank of Canada
BNP Paribas
SociDetDe GDenDerale
ATB Financial
Transfer Agent
Valiant Trust Company
Head Office
2900, 450 - 1st Street SW
Calgary, AB
T2P 5H1
Phone: 403.261.6081
Fax: 403.451.4100
Web: www.peyto.com
Stock Listing Symbol: PEY.un
Toronto Stock Exchange
>>
%SEDAR: 00019597E
