SYMBOL: PEY.UN - TSX
CALGARY, Nov. 9 /CNW/ - Peyto Energy Trust ("Peyto") is a leader in the
exploration and development of natural gas in western Canada. Our core areas
are located in Alberta's premier gas exploration area, the Deep Basin. The
combination of our solid foundation and our ability to profitably find and
develop oil and natural gas reserves makes Peyto a unique energy trust. We are
proud to present our operating and financial results for the third quarter of
the 2005 fiscal year.
The following summarizes the Trust's foundation.
- Long reserve life - Proved 12.2 years, Proved Plus Probable
17.2 years at the beginning of 2005
- Low operating costs - $1.41/boe, nine months ending September 30,
2005
- Low base general and administrative costs - $0.10/boe, nine months
ending September 30, 2005
- High netback - $34.69/boe, nine months ending September 30, 2005
- High operatorship - 97% of production
- Low cash distribution payout ratio - 47% of funds from operations for
the nine months ended September 30, 2005.
- Low debt to funds from operations ratio - 0.67 (net debt, before
provision for future compensation, divided by annualized third
quarter 2005 funds from operations)
- Since inception, Peyto has raised a total of $322.1 million issuing
units from treasury, accumulated earnings of $275.2 million, and
distributed $234.4 million to unitholders
- Transparent capital structure - no convertible debentures, no
exchangeable shares, no stock options, no warrants
The following summarizes performance highlights for the third quarter of
2005.
- Production growth - production increased 18% from 19,264 boe/d in the
third quarter of 2004 to 22,646 boe/d in the third quarter of 2005
- Per unit production growth - increased 17% per trust unit after
adjusting for debt and bonuses
- Per unit funds from operations growth - was a record $0.78/unit which
was 30% higher than third quarter of 2004
- Capital expenditures - $93 million was spent to find and develop new
natural gas reserves
- Cash distributions per unit increased by 36% from the third quarter
of 2004 while the payout ratio remained low at 46%. A total of
$35.5 million or $0.36 per unit was distributed to unitholders in the
third quarter of 2005.
Natural gas volumes recorded in thousand cubic feet (mcf) are converted
to barrels of oil equivalent (boe) using the ratio of six (6) thousand cubic
feet to one (1) barrel of oil (bbl).
<<
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3 Months Ended % 9 Months Ended %
Sep 30 Sep 30
2005 2004 Change 2005 2004 Change
-------------------------------------------------------------------------
Operations
Production
Natural gas
(mcf/d) 108,460 91,782 18% 106,143 85,778 24%
Oil & NGLs
(bbl/d) 4,569 3,967 15% 4,520 3,722 21%
Barrels of
oil equiv-
alent (boe/d
(at) 6:1) 22,646 19,264 18% 22,211 18,018 23%
Product prices
Natural gas
($/mcf) 8.67 7.00 24% 8.17 7.30 12%
Oil & NGLs
($/bbl) 57.22 43.13 33% 54.56 41.02 33%
Operating
expenses
($/boe) 1.70 1.08 57% 1.41 1.06 33%
Transportation
($/boe) 0.66 0.68 -3% 0.67 0.67 0%
Field netback
($/boe) 38.39 31.72 21% 35.98 31.36 15%
General &
administrative
expenses
($/boe) 0.13 0.05 160% 0.10 0.16 -38%
Interest
expense
($/boe) 1.16 1.03 13% 1.13 1.00 13%
Financial
($000, except
per unit)
Revenue 110,566 74,866 48% 304,062 213,374 43%
Royalties (net
of ARTC) 25,654 15,529 65% 73,280 49,986 47%
Funds from
operations 77,179 54,211 42% 210,363 148,771 41%
Funds from
operations
per unit(x) 0.78 0.60 30% 2.16 1.63 33%
Cash
distributions 35,505 23,320 52% 99,875 67,216 49%
Cash
distributions
per unit(x) 0.36 0.265 36% 1.025 0.735 39%
Percentage of
funds from
operations
distributed 46 43 7% 47 45 4%
Earnings 37,702 21,650 74% 100,823 76,340 32%
Earnings per
diluted
unit(x) 0.38 0.24 58% 1.04 0.83 25%
Capital
expenditures 93,001 55,565 67% 250,806 153,820 63%
Weighted
average
trust units
outstan-
ding(x) 98,584,597 91,450,544 8% 97,372,966 91,448,134 6%
As at
September 30
Net debt
(before future
compensation
expense) 207,225 234,731 -12%
Unitholders'
equity 362,858 127,085 186%
Total assets 885,464 516,385 71%
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(x) Note: prior periods restated for 2 for 1 split of trust units
completed May 31, 2005.
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
bonuses, 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.
-------------------------------------------------------------------------
3 Months 9 Months
Ended Sep 30 Ended Sep 30
2005 2004 2005 2004
-------------------------------------------------------------------------
Earnings 37,702 21,650 100,823 76,340
Items not requiring cash:
Provision for bonuses 14,143 20,298 39,188 31,910
Future income tax expense 11,056 490 28,786 10,419
Depletion, depreciation and
accretion 14,278 11,773 41,566 30,102
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Funds from operations 77,179 54,211 210,363 148,771
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Quarterly Review
On August 18, 2005, Peyto announced that it had entered into an agreement
to sell, on a bought deal basis, 5,000,000 trust units at a price of
$30.55 per trust unit. This offering closed on September 8, 2005, with Peyto
receiving net proceeds of $145 million. These funds along with cashflow and
banklines will be used for finding and developing new oil and gas reserves in
Peyto's core areas.
Peyto was very active in the third quarter building value by drilling,
completing and connecting new gas wells. Total capital invested in the quarter
was $93 million. Much of the activity was focused on those drier, accessible
lands in and around our core areas of Wildhay and Sundance. Costs associated
with drilling and completing new reserves accounted for $70.3 million of the
total, while pipeline and facility construction accounted for $13.5 million.
Over $9 million was invested in new land and seismic evaluation which added to
our inventory of drilling prospects. Peyto drilled 32 gross (26.4 net) wells
in the third quarter of 2005 and brought 41.7 net zones on production.
During the quarter, the Sundance gas plant underwent a major turnaround
resulting in 3 days of lost production. This scheduled maintenance decreased
average production by 400 boe per day. Our baseline operating costs have
increased from $1.06/boe in 2004 to a current $1.35 to $1.40/boe. This
increase is attributable to rising service sector costs as well as a small
shift in our fixed costs due to the natural decline in productivity of our
older wells. As wells mature and production declines, the percentage of
royalties paid on that production also declines. This reduction in royalties
per unit of production more than offsets the operating costs per unit of
production, thereby causing netbacks to increase. Quarterly operating costs
can fluctuate due to seasonal variances such as weather and access. Commodity
prices, after hedging, were very strong during the quarter averaging $8.67 per
mcf of natural gas and $57.22 per barrel of oil and natural gas liquids.
Even though we were successful finding and developing new gas reserves
during the quarter, our average production showed no meaningful growth from
the previous quarter. We are confident that the projects we have invested
capital in will generate excellent returns. The value of these projects will
be evident when the independent engineers have prepared their reserve report
at year end. Until such time, we can look at other parameters for an idea of
how well our business is performing.
- Average productivity per new zone on production in 2005 is higher
than 2004.
- Current production from the proven producing assets in the year end
2004 reserve report continue to track the predicted forecast assigned
to them by the independent engineers.
- Estimated total new net production brought onstream for the first
nine months of 2005 is 8,600 boe/d. Assuming all of the capital spent
to date in 2005, $251 million, went to find and develop this
production the cost would be a very competitive $29,000 per boe/d.
- Netback before hedging for the third quarter 2005 was $44.51 per boe,
which was 46% higher than third quarter 2004 netback before hedging
of $30.50 per boe.
Activity Update
Production is currently 22,600 boe/d, which is flat from three months ago
when we reported our second quarter results. The lack of production growth is
attributable to the wet surface conditions in areas where we have excess gas
processing capacity and a lack of processing capacity in Sundance where we
have better surface access. As the ground begins to freeze in our northern
areas of operation, we will be in a position to begin drilling, completing and
producing wells where we have excess processing capacity. In order to
accommodate more gas production in the Sundance area, we are constructing a
new 20 mmcf/d gas plant in Wildhay (west of the existing Sundance plant) and
expanding existing capacity of the Sundance plant. The Wildhay plant is
scheduled to commence operations in the first quarter of 2006.
To date in 2005, Peyto has drilled 101 gross (84.5 net) wells which is a
44% increase over the same period in 2004. We have brought onstream 90.5 net
zones and currently have 37 net zones that are drilled and waiting on
completion and tie-in. At this time we have 7 of our 9 drilling rigs active in
our southern core areas where gas processing capacity is limited in the near
term, while the remaining 2 rigs have finally gained access to our northern
core areas where we have excess gas processing capacity. Additional rigs will
be moved north for our winter drilling program as freeze up continues.
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. It is meant to be methodical and consistent and to avoid
speculation. This forward price averaging gives stability to both our monthly
distributions and capital expenditure program.
The forward price averaging is meant to be on roughly 70% of current
production net of royalties or a little more than 50% of the absolute current
production. The forward average price is 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 $10.00/mcf during the third
quarter of 2005, an increase of 47 percent from $6.79/mcf reported for the
equivalent period in 2004. Oil and natural gas liquids prices averaged
$62.73/bbl up 32 percent from $47.64/bbl a year earlier. Hedging activity for
the third quarter of 2005 reduced Peyto's price achieved by $7.47/boe. The
third quarter hedging loss was $15.6 million for year to date total of
$17.2 million.
Peyto has committed to the forward sale of 479,300 barrels of crude oil
at an average price of $64.89 per barrel and 25.8 million gigajoules (GJ) of
natural gas at an average price of $8.08 per GJ. This presold volume
represents less than 5% of the total proven reserves that were assigned at the
beginning of the year. Based on the historical heating value of Peyto's
natural gas, the price per mcf on the forward sale will be $9.45, which is 9%
higher than the price realized in the third quarter of 2005.
Recent Industry Development
The Canadian federal government has recently made a number of
pronouncements on tax and other issues relating to publicly listed
flow-through entities (income trusts and limited partnerships). The resulting
uncertainty has contributed to increased volatility and a significant loss of
market value for the income trust sector.
The concerns of the government are the perceived loss of tax revenue due
to taxable corporations converting to the income trust structure and a
reduction in productivity as income trusts are more focused on maintaining
distributions than economic growth. These concerns are not supported by
Peyto's historical performance. In our five-year history from 1998 to 2003 as
a taxable corporation, Peyto did not pay any income taxes. The conversion from
corporation to income trust of Peyto in July 2003 was a significant taxable
event for the shareholders with no deferral. Since conversion to an income
trust, Peyto has paid out $234.4 million in distributions to unitholders, of
which historically 61% has been designated as taxable income. In terms of
productivity and reinvestment, Peyto continues to be an active operator as we
focus on growing production through exploration and development activities. In
fact one of the main reasons for converting to an income trust was to maintain
our strong history of entrepreneurial success. Since the trust conversion, we
have invested approximately $621 million in exploration and development
expenditures. All of our investments during this period have been made
exclusively in Canada. We believe that the trust structure enforces capital
reinvestment discipline which is not always present in mature industries under
a corporation structure, and that distribution of a portion of cash flow to
unitholders provides the opportunity for reinvestments in other sectors of the
economy. We are proud of our contributions to both the Alberta and Canadian
economy, from the standpoints of employment, tax revenue and productivity, as
they are substantial and transparent.
The income trust model has served as an effective vehicle for Canadians
to invest for purposes of generating income and funding for retirement. Any
potential tax levy or additional restrictions on income trusts would
negatively affect the income that these investors currently receive. While the
oil and gas business is focused in western Canada, the ownership of the energy
business is predominantly in central Canada, thus, these actions will affect
all Canadians. Peyto strongly encourages unitholders to participate in the
process so that their opinions can be accounted for in the government's
resolution of these important issues. For written submission, send an e-mail
to: trusts-fiducies(at)fin.gc.ca. To contact the Minister of Finance, you may
write to The Honourable Ralph Goodale, Department of Finance, 140 O'Connor
Street, Ottawa, Ontario K1A 0A6, or you may reach him at phone number
(613) 996-4743, fax number (613) 996-9790, or via e-mail at
goodale.R(at)parl.gc.ca. To contact your Member of Parliament, direct your
comments to www.canada.gc.ca/directories/direct_e.html.
Outlook
Mr. Glenn Booth has been appointed Peyto's first Vice-President, Land.
Glenn brings extensive land and management skills to Peyto. Rick Braund will
continue to act as a landman and director.
Our current Vice-President of Finance, Sandra Brick, will be retiring
effective January 1, 2006. On behalf of the directors, staff and unitholders
of Peyto we would like to thank Ms. Brick for her contribution to the success
of Peyto and wish her the best in her retirement.
Effective January 1, 2006, Ms. Kathy Turgeon, CA, Peyto's current
Controller, will be appointed Vice-President, Finance. Kathy was appointed
Controller in April, 2004 and brings strong accounting and corporate reporting
skills that will complement Peyto's management team. We are confident that
this transition will be seamless.
Careful review would confirm that Peyto continues to demonstrate the
ability to add assets it develops in-house with lower costs and longer reserve
life than acquisitions would provide. The advantage to focused geological and
geographic development allows economies of scale while providing for
repeatable growth. We are on track to add more producing reserves this year
than any prior year and our cost to develop these reserves is expected to
remain among the lowest in the industry. As a result of the ongoing expansion
of our technical team, our inventory of drilling opportunities has never been
greater. The majority of our capital program continues to involve drilling,
completion and tie in of lower risk development gas wells. These expenditures
will be funded with a combination of funds from operations, working capital,
equity and bank lines.
Our performance combined with the foundation we have built proves that
our business strategy is successful and unique. If you are interested in
learning more about our business and willing to invest some of your time to
understand Peyto's past and future, we encourage you to visit the Peyto
website at www.peyto.com where you will find a current presentation, financial
and historical news releases and an updated insider trading summary.
Conference Call and Webcast
A conference call will be held with the senior management of Peyto to
answer questions with respect to the 2005 third quarter results on Thursday,
November 10th 2005 at 8:30 a.m. Mountain Standard Time (MST), 10:30 a.m.
Eastern Standard Time (EST). To participate, please call 1-416-640-4127
(Toronto area) or 1-866-250-4892 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 21158455 followed by
the pound key. The replay will be available at 10:30 a.m. MST, 12:30 p.m. EST
Thursday, November 10, 2005 until 11:59 p.m. EST on Thursday, November 17,
2005. The conference call can also be accessed through the internet at
http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID(equal sign)1276880 for
the English version or
http://www.cnw.ca/fr/webcast/viewEvent.cgi?eventID(equal sign)1276880 for the
French version. The archived conference call will be available on the Peyto
website at www.peyto.com.
Don T. Gray
President and Chief Executive Officer
November 9, 2005
Certain information set forth in this document and 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
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 unaudited interim consolidated financial statements for
the period ended September 30, 2005 and the audited consolidated financial
statements of Peyto Energy Trust ("Peyto") for the year ended December 31,
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 November 8, 2005. 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 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 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
bonuses, 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
23.8 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, 2004, we
had total proved plus probable reserves of 129.5 million barrels of oil
equivalent with a reserve life of 17.2 years as evaluated by our independent
petroleum engineers. Our production is weighted as to approximately 80%
natural gas and 20% 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 six 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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2005
($000 except per unit amounts) Q3 Q2 Q1
-------------------------------------------------------------------------
Total revenue (net of royalties) 84,912 73,473 72,397
Funds from operations 77,179 66,548 66,636
Per unit - basic(x) 0.78 0.69 0.69
Per unit - diluted(x) 0.78 0.69 0.69
Earnings (loss) 37,702 25,690 37,431
Per unit - basic(x) 0.38 0.27 0.39
Per unit - diluted(x) 0.38 0.27 0.39
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2004 2003
($000 except per unit amounts) Q4 Q3 Q2 Q1 Q4
-------------------------------------------------------------------------
Total revenue (net of royalties) 66,024 59,337 53,853 50,197 45,901
Funds from operations 60,334 54,211 48,548 46,012 41,371
Per unit - basic(x) 0.65 0.60 0.53 0.51 0.46
Per unit - diluted(x) 0.65 0.60 0.53 0.51 0.46
Earnings (loss) (2,558) 21,650 30,347 24,343 6,203
Per unit - basic(x) (0.03) 0.24 0.33 0.27 0.07
Per unit - diluted(x) (0.03) 0.24 0.33 0.27 0.07
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(x) Note: prior periods restated for 2 for 1 split of trust units
completed May 31, 2005.
RESULTS OF OPERATIONS
Production
-------------------------------------------------------------------------
Three Months Nine Months
Ended Sep 30 Ended Sep 30
2005 2004 2005 2004
-------------------------------------------------------------------------
Natural gas (mmcf/d) 108.5 91.8 106.1 85.8
Oil & natural gas liquids
(bbl/d) 4,569 3,967 4,520 3,722
Barrels of oil equivalent
(boe/d) 22,646 19,264 22,211 18,018
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Natural gas production averaged 108.5 mmcf/d in the third quarter of
2005, 18 percent higher than the 91.8 mmcf/d reported for the same period in
2004. Oil and natural gas liquids production averaged 4,569 bbl/d, an increase
of 15 percent from 3,967 bbl/d reported in the prior year. Year to date
production increased 23 percent from 18,018 boe/d to 22,211 boe/d. The
production increases are directly attributable to Peyto's ongoing drilling
program.
Commodity Prices
-------------------------------------------------------------------------
Three Months Nine Months
Ended Sep 30 Ended Sep 30
2005 2004 2005 2004
-------------------------------------------------------------------------
Natural gas ($/mcf) 10.00 6.79 8.60 7.17
Hedging - gas ($/mcf) (1.33) 0.21 (0.43) 0.13
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Natural gas - after
hedging ($/mcf) 8.67 7.00 8.17 7.30
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Oil and natural gas
liquids ($/bbl) 62.73 47.64 58.48 43.69
Hedging - oil ($/bbl) (5.51) (4.51) (3.92) (2.67)
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Oil and natural gas liquids -
after hedging ($/bbl) 57.22 43.13 54.56 41.02
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Total Hedging ($/boe) (7.47) 0.09 (2.84) 0.08
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Our natural gas price before hedging averaged $10.00/mcf during the third
quarter of 2005, an increase of 47 percent from $6.79/mcf reported for the
equivalent period in 2004. Oil and natural gas liquids prices averaged
$62.73/bbl up 32 percent from $47.64/bbl a year earlier. Hedging activity for
the third quarter of 2005 reduced Peyto's price achieved by $7.47/boe.
Expectations are for commodity prices to remain strong relative to historical
pricing.
Revenue
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Three Months Nine Months
Ended Sep 30 Ended Sep 30
($000) 2005 2004 2005 2004
-------------------------------------------------------------------------
Natural gas 99,769 57,321 249,099 168,430
Oil and natural gas liquids 26,370 17,387 72,173 44,552
Hedging gain (loss) (15,573) 158 (17,210) 392
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Total revenue 110,566 74,866 304,062 213,374
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For the three months ended September 30, 2005, gross revenue increased 48
percent to $110.6 million from $74.9 million for the same period in 2004. The
increase in revenue for the period was a result of increased production
volumes and pricing as detailed in the following table:
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Three Months ended Sep 30
2005 2004 Change $million
-------------------------------------------------------------------------
Natural gas
Volume (mcf/d) 108,460 91,782 16,678
Volume (mmcf) 9,978.3 8,443.9 1,534.4 10.7
Price ($/mcf) $8.67 $7.00 $1.67 16.7
Oil & NGL
Volume (bbl/d) 4,569 3,967 602
Volume (mbbl) 420.4 364.9 55.5 2.4
Price ($/bbl) $57.22 $43.13 $14.09 5.9
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Total revenue ($million) 110.6 74.9 35.7 35.7
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-------------------------------------------------------------------------
Nine Months ended Sep 30
2005 2004 Change $million
-------------------------------------------------------------------------
Natural gas
Volume (mcf/d) 106,143 85,778 20,365
Volume (mmcf) 28,977.0 23,503.2 5,473.8 40.0
Price ($/mcf) $8.17 $7.30 $0.87 25.2
Oil & NGL
Volume (bbl/d) 4,520 3,722 798
Volume (mbbl) 1,234.1 1,019.8 214.3 8.8
Price ($/bbl) $54.56 $41.02 $13.54 16.7
-------------------------------------------------------------------------
Total revenue ($million) 304.1 213.4 90.7 90.7
-------------------------------------------------------------------------
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 Nine Months
Ended Sep 30 Ended Sep 30
2005 2004 2005 2004
-------------------------------------------------------------------------
Royalties, net of ARTC ($000) 25,654 15,529 73,280 49,986
% of sales 23 21 24 24
$/boe 12.31 8.76 12.09 10.12
-------------------------------------------------------------------------
For the third quarter of 2005, royalties averaged $12.31/boe or
approximately 23 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.
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 Nine Months
Ended Sep 30 Ended Sep 30
2005 2004 2005 2004
-------------------------------------------------------------------------
Operating costs ($000)
Field expenses 5,192 2,951 13,250 8,203
Processing and gathering income (1,655) (1,036) (4,697) (2,946)
-------------------------------------------------------------------------
Total operating costs 3,537 1,915 8,553 5,257
-------------------------------------------------------------------------
$/boe 1.70 1.08 1.41 1.06
-------------------------------------------------------------------------
Transportation 1,384 1,208 4,087 3,311
-------------------------------------------------------------------------
$/boe 0.66 0.68 0.67 0.67
-------------------------------------------------------------------------
Operating costs were $3.5 million in the third quarter compared to
$1.9 million during the same period a year earlier. On a unit-of-production
basis, operating costs averaged $1.70/boe in the third quarter of 2005
compared to $1.08/boe for the third quarter of 2004.
Netbacks
Operating netbacks represent the profit margin associated with the
production and sale of petroleum and natural gas. The primary factors that
produce Peyto's strong netbacks are a low cost structure and the high heat
content of our natural gas that results in higher commodity prices.
-------------------------------------------------------------------------
Three Months Nine Months
Ended Sep 30 Ended Sep 30
($/boe) 2005 2004 2005 2004
-------------------------------------------------------------------------
Sale Price 53.06 42.24 50.15 43.22
Less:
Royalties 12.31 8.76 12.09 10.12
Operating costs 1.70 1.08 1.41 1.06
Transportation 0.66 0.68 0.67 0.67
-------------------------------------------------------------------------
Operating netback 38.39 31.72 35.98 31.37
General and administrative 0.13 0.05 0.10 0.16
Interest on long-term debt 1.16 1.03 1.13 1.00
Capital tax 0.06 0.05 0.06 0.06
-------------------------------------------------------------------------
Cash netback 37.04 30.59 34.69 30.15
-------------------------------------------------------------------------
General and Administrative Expenses
-------------------------------------------------------------------------
Three Months Nine Months
Ended Sep 30 Ended Sep 30
2005 2004 2005 2004
-------------------------------------------------------------------------
G&A expenses ($000) 1,620 1,048 4,560 3,142
Overhead recoveries (1,356) (967) (3,976) (2,349)
-------------------------------------------------------------------------
Net G&A expenses 264 81 584 793
-------------------------------------------------------------------------
$/boe 0.13 0.05 0.10 0.16
-------------------------------------------------------------------------
General and administrative expenses before overhead recoveries increased
to $1.6 million in the third quarter of 2005, as compared to $1.0 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 decreased to $0.10 per boe from $0.16 per boe in 2004.
Interest Expense
-------------------------------------------------------------------------
Three Months Nine Months
Ended Sep 30 Ended Sep 30
2005 2004 2005 2004
-------------------------------------------------------------------------
Interest expense ($000) 2,422 1,833 6,845 4,941
$/boe 1.16 1.03 1.13 1.00
-------------------------------------------------------------------------
Third quarter 2005 interest expense was $2.4 million or $1.16/boe
compared to $1.8 million or $1.03/boe a year earlier. During 2005, average
debt levels have increased to partially fund Peyto's capital expenditures
program. Interest rates continue to be favourable and are not expected to
increase substantially in the short-term.
Depletion, Depreciation and Accretion
The third quarter 2005 provision for depletion, depreciation and
accretion totaled $14.3 million as compared to $11.8 million for the same
period in 2004. Year to date DD&A totaled $41.6 million in 2005 compared to
$30.1 million in 2004. On a unit-of-production basis, depletion, depreciation
and accretion costs averaged $6.86/boe as compared to $6.10/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.
Income Taxes
The current provision for future income tax increased to $28.8 million
for the first three quarters of 2005 from $10.4 million in 2004. The change is
primarily due to increased profitability resulting from higher production
volumes and commodity prices.
HEDGING
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 first three quarters of 2005, we recorded a hedging loss of
$17.2 million as compared to a hedging gain of $0.4 million in the first three
quarters of 2004. A summary of contracts outstanding in respect of the hedging
activities are as follows:
Crude Oil Price
Period Hedged Type Daily Volume (CAD)
-------------------------------------------------------------------------
October 1 to December 31, 2005 Fixed price 300 bbl $54.35/bbl
October 1 to December 31, 2005 Fixed price 250 bbl $57.52/bbl
October 1 to December 31, 2005 Fixed price 200 bbl $52.07/bbl
October 1 to December 31, 2005 Fixed price 200 bbl $53.15/bbl
October 1 to December 31, 2005 Fixed price 200 bbl $55.20/bbl
October 1 to December 31, 2005 Fixed price 200 bbl $60.50/bbl
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)
--------------------------------------------------------------------------
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.71/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.70/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.80/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.45/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.55/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.70/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $7.00/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $7.27/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.42/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.65/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.80/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.90/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $7.01/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $7.11/GJ
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
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 $10.28/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 $10.06/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 September 30, 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 $2.3 million per
annum.
LIQUIDITY AND CAPITAL RESOURCES
Funds from Operations
-------------------------------------------------------------------------
Three Months Nine Months
Ended Sep 30 Ended Sep 30
($000) 2005 2004 2005 2004
-------------------------------------------------------------------------
Earnings 37,702 21,650 100,823 76,340
Items not requiring cash:
Provision for bonuses 14,143 20,298 39,188 31,910
Future income tax expense 11,056 490 28,786 10,419
Depletion, depreciation &
accretion 14,278 11,773 41,566 30,102
-------------------------------------------------------------------------
Funds from operations 77,179 54,211 210,363 148,771
-------------------------------------------------------------------------
For the quarter ended September 30, 2005, funds from operations totaled
$77.2 million or $0.78 per unit, representing a 42% increase from the
$54.2 million, or $0.60 per unit during the same period 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.
At September 30, 2005, $220 million was drawn under the facility.
Subsequent to quarter-end, an additional $50 million of bank debt was repaid.
Working capital liquidity is maintained by drawing from and repaying the
unutilized credit facility as needed. At September 30, 2005, we had a working
capital deficit of $40.7 million.
We believe that funds generated from our operations, together with
borrowings under our credit facility and proceeds, if any, from equity issued
will be sufficient to finance our current operations and planned capital
expenditure program. We anticipate that our 2005 capital expenditures will be
between $340 and $360 million. In 2005, almost all of Peyto's capital
expenditures are discretionary focused on exploration, development and
acquisition activity. The majority of these expenditures will be employed to
drill, complete and tie-in natural gas wells adjacent to Peyto's existing
infrastructure. Peyto has the flexibility to match planned capital
expenditures to actual cash flow.
Capital
At November 9, 2005, 102,031,358 trust units were outstanding (September
30, 2005 - 101,993,139). On May 31, 2005, Peyto trust units split 2 for 1.
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 October 14, 2005 38,219 trust units were issued
at a price of $29.06 per trust unit pursuant to the DRIP.
On August 18, 2005, Peyto announced that it had entered into an agreement
to sell, on a bought deal basis, 5,000,000 trust units at a price of $30.55
per trust unit. This offering closed on September 8, 2005, with Peyto
receiving net proceeds of $145 million.
Authorized: Unlimited number of voting trust units
Issued and Outstanding:
Trust Units (no par value) Number of Amount
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 - (7,671,305)
Trust units issued pursuant to DRIP 145,305 4,085,186
-------------------------------------------------------------------------
Balance, September 30, 2005 101,993,139 320,956,420
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Market & Reserves Based Bonuses
The Trust awards bonuses to employees and key consultants. The bonus
structure is comprised of market and reserves based components.
Under the reserves based component, the bonus pool, on an annual basis,
will be initially comprised of 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%. The independent reserves
evaluation for 2005 will be completed in January 2006. A quarterly provision
for the reserves based bonus is based on internally estimated proved producing
reserves additions using 2005 forecast commodity prices adjusted for changes
in debt, equity and distributions. Proved producing reserves are estimated
based on year-to-date production growth. This methodology can generate interim
results which may vary significantly from the final bonus paid. A provision
for compensation expense of $2.9 million was recorded in the nine months ended
September 30, 2005.
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. The bonus 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 of the bonus to be paid.
Based on the five day weighted average trading price of the trust units
for the period ended September 30, 2005, compensation costs related to
4.9 million non-vested rights, with an average grant price of $16.36, total
$93.6 million. The Trust records a non-cash provision for future compensation
expense over the life of the rights. The cumulative provision totals
$64.6 million of which $39.7 million was recorded in the nine months ended
September 30, 2005.
Capital Expenditures
Net capital expenditures for the third quarter of 2005 totaled
$93.0 million. Exploration and development related activity represented
$79.3 million or 85% of the total, while expenditures on facilities, gathering
systems and equipment totaled $13.5 million or 15% of the total. The following
table summarizes capital expenditures for the year.
-------------------------------------------------------------------------
Three Months Nine Months
Ended Sep 30 Ended Sep 30
($000) 2005 2004 2005 2004
-------------------------------------------------------------------------
Land 3,300 568 8,592 3,203
Seismic 5,749 1,094 8,251 2,454
Drilling - Exploratory &
Development 70,274 44,824 190,171 106,734
Production Equipment, Facilities
& Pipelines 13,483 8,972 43,576 38,099
Acquisitions & Dispositions - 104 - 3,255
Office Equipment 195 3 216 75
-------------------------------------------------------------------------
Total Capital Expenditures 93,001 55,565 250,806 153,820
-------------------------------------------------------------------------
Cash Distributions
-------------------------------------------------------------------------
Three Months Nine Months
Ended Sep 30 Ended Sep 30
2005 2004 2005 2004
-------------------------------------------------------------------------
Funds from operations ($000) 77,179 54,211 210,363 148,771
Distributions ($000) 35,505 23,320 99,875 67,216
Distributions per unit ($)(x) 0.36 0.255 1.025 0.735
Payout ratio (%) 46 43 47 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:
-------------------------------------------------------------------------
$
-------------------------------------------------------------------------
2005 233,173
2006 953,484
2007 953,484
2008 1,096,641
2009 1,096,641
2010 1,096,641
2011 1,096,641
-------------------------------------------------------------------------
6,526,705
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 the first nine months of 2005, the Trust paid distributions to the
unitholders in the amount of $99.9 million (2004 - $67.2 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 15, 2005 $0.11
March 2005 March 31, 2005 April 15, 2005 $0.11
April 2005 April 29, 2005 May 13, 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
(x) Note: prior periods 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 operating 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 has an ongoing
commodity price risk management policy that provides for downside protection
on a portion of its future production while allowing access, in certain cases,
to the upside price movements.
Although our focus is on our 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 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 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 when appropriate, through the issuance
of equity.
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 therefrom 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 reserves based bonus. 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, 2004 were audited by independent petroleum engineers Paddock
Lindstrom & Associates Ltd. Paddock has been evaluating reserves in this area
and for Peyto for 6 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, with the accretion charged to earnings and for
revisions to the estimated future cash flows. By their nature, these estimates
are subject to measurement uncertainty and the impact on the financial
statements could be material.
Future Market Based Bonus
The provision for future market based bonus 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.
Reserves Based Bonus
The reserves based bonus is calculated based on the year end independent
reserves evaluation which will be completed in January 2006. A quarterly
provision for the reserves based bonus is based on estimated proved producing
reserves 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.
CHANGES IN ACCOUNTING POLICIES
None
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
Q3 Q2 Q1 Q4 Q3
-------------------------------------------------------------------------
Operations
Production
Natural gas
(mcf/d) 108,460 106,866 103,043 97,968 91,782
Oil & NGLs (bbl/d) 4,569 4,653 4,337 4,360 3,967
Barrels of oil
equivalent (boe/d
(at) 6:1) 22,646 22,464 21,511 20,688 19,264
Average product
prices
Natural gas ($/mcf) 8.67 8.00 7.81 7.58 7.00
Oil & natural gas
liquids ($/bbl) 57.22 51.03 55.52 46.82 43.13
Average operating
expenses ($/boe) 1.70 1.30 1.22 1.03 1.08
Average transportation
costs ($/boe) 0.66 0.68 0.68 0.77 0.68
Field netback ($/boe) 38.39 33.97 35.50 32.90 31.72
General &
administrative
expense ($/boe) 0.13 0.10 0.06 0.01 0.05
Interest expense
($/boe) 1.16 1.25 0.97 1.03 1.03
Financial ($000
except per unit)
Revenue 110,566 99,427 94,069 87,127 74,866
Royalties
(net of ARTC) 25,654 25,954 21,672 21,103 15,529
Funds from
operations 77,179 66,548 66,636 60,334 54,211
Funds from
operations
per unit(x) 0.78 0.69 0.69 0.65 0.60
Cash distributions 35,505 33,898 30,472 26,443 23,320
Cash distributions
per unit(x) 0.36 0.35 0.315 0.285 0.255
Percentage of funds
from operations
distributed 46% 51% 46% 44% 43%
Earnings 37,702 25,690 37,431 (2,558) 21,650
Earnings per
diluted unit(x) 0.38 0.27 0.39 (0.03) 0.24
Capital
expenditures 93,001 58,730 99,074 76,953 55,565
Weighted average
trust units
outstanding(x) 98,584,597 96,848,988 96,664,210 92,494,022 91,450,544
(x) Note: prior periods restated for 2 for 1 split of trust units
completed May 31, 2005.
Peyto Energy Trust
Consolidated Balance Sheets
(unaudited)
September 30, December 31,
2005 2004
$ $
-------------------------------------------------------------------------
Assets
Current
Cash 66,774,302 -
Accounts receivable 75,247,546 58,992,005
Due from private placements - 27,080,066
Prepaid expenses and deposits 1,985,542 5,262,778
-------------------------------------------------------------------------
144,007,390 91,334,849
Property, plant and equipment
(Notes 2 and 3) 741,457,062 531,241,786
-------------------------------------------------------------------------
885,464,452 622,576,635
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities and Unitholders' Equity
Current
Accounts payable and accrued liabilities 119,961,687 124,753,199
Capital taxes payable 142,680 483,081
Cash distributions payable 11,128,537 9,067,811
Provision for future market and reserves
based bonus 53,466,667 22,298,937
-------------------------------------------------------------------------
184,699,571 156,603,028
-------------------------------------------------------------------------
Long-term debt (Note 3) 220,000,000 180,000,000
Provision for future market based bonus 14,141,495 6,121,097
Asset retirement obligations 4,304,265 3,328,834
Future income taxes 99,461,195 70,675,002
-------------------------------------------------------------------------
337,906,955 260,124,933
-------------------------------------------------------------------------
Unitholders' equity
Unitholders' capital (Note 4) 320,956,420 138,953,026
Units to be issued (Note 4) 1,110,640 27,052,850
Accumulated earnings 275,180,902 174,358,093
Accumulated cash distributions (Note 5) (234,390,036) (134,515,295)
-------------------------------------------------------------------------
362,857,926 205,848,674
-------------------------------------------------------------------------
885,464,452 622,576,635
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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
(unaudited)
Three Months ended Nine Months ended
September 30 September 30
2005 2004 2005 2004
$ $ $ $
-------------------------------------------------------------------------
Revenue
Petroleum and
natural gas sales,
net 84,912,303 59,337,285 230,782,091 163,387,870
-------------------------------------------------------------------------
Expenses
Operating (Note 6) 3,537,387 1,914,825 8,552,969 5,256,728
Transportation 1,384,038 1,207,772 4,087,034 3,310,547
General and
administrative 264,216 81,394 583,890 793,222
Future market and
reserves based
bonus provision 14,143,405 20,298,782 39,188,128 31,910,274
Interest 2,422,468 1,832,995 6,844,870 4,940,808
Depletion,
depreciation and
accretion
(Note 2) 14,277,710 11,772,970 41,566,197 30,102,702
-------------------------------------------------------------------------
36,029,224 37,108,738 100,823,088 76,314,281
-------------------------------------------------------------------------
Earnings before
taxes 48,883,079 22,228,547 129,959,003 87,073,589
-------------------------------------------------------------------------
Taxes
Future income tax
expense 11,056,202 489,816 28,786,194 10,418,523
Capital tax expense 125,000 89,184 350,000 315,202
-------------------------------------------------------------------------
11,181,202 579,000 29,136,194 10,733,725
-------------------------------------------------------------------------
Net earnings for
the period 37,701,877 21,649,547 100,822,809 76,339,864
Accumulated
earnings,
beginning
of period 237,479,025 155,266,776 174,358,093 100,576,459
-------------------------------------------------------------------------
Accumulated
earnings, end of
period 275,180,902 176,916,323 275,180,902 176,916,323
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per unit
(Note 4)
Basic 0.38 0.24 1.04 0.83
Diluted 0.38 0.24 1.04 0.83
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
Peyto Energy Trust
Consolidated Statements of Cash Flows
(Unaudited)
Three Months ended Nine Months ended
September 30 September 30
2005 2004 2005 2004
$ $ $ $
-------------------------------------------------------------------------
Cash provided by
(used in)
Operating Activities
Net earnings for
the period 37,701,877 21,649,547 100,822,809 76,339,864
Items not requiring
cash:
Future income
tax expense 11,056,202 489,816 28,786,194 10,418,523
Depletion,
depreciation and
accretion 14,277,710 11,772,970 41,566,197 30,102,702
Change in non-cash
working capital
related to operating
activities 8,273,321 27,006,336 9,427,262 33,010,827
-------------------------------------------------------------------------
71,309,110 60,918,669 180,602,462 149,871,916
-------------------------------------------------------------------------
Financing Activities
Issue of trust units,
net of costs 148,265,847 - 156,061,184 -
Distribution
payments (35,504,792) (23,319,920) (99,874,741) (67,216,250)
Increase (decrease)
in bank debt (60,000,000) 10,000,000 40,000,000 40,000,000
Change in non-cash
working capital
related to
financing
activities 501,226 - 29,140,792 9,977,133
-------------------------------------------------------------------------
53,262,281 (13,319,920) 125,327,235 (17,239,117)
-------------------------------------------------------------------------
Investing Activities
Additions to
property, plant
and equipment (93,001,245) (55,565,543) (250,806,042) (153,820,178)
Change in non-cash
working capital
related to
investing
activities 28,787,596 7,966,794 11,650,648 596,161
-------------------------------------------------------------------------
(64,213,649) (47,598,749) (239,155,394) (153,224,017)
-------------------------------------------------------------------------
Net increase
(decrease)
in cash 60,357,742 - 66,774,303 (20,591,218)
Cash, beginning
of period 6,416,561 - - 20,591,218
-------------------------------------------------------------------------
Cash, end
of period 66,774,303 - 66,774,303 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplemental cash flow information - Note 8
See accompanying notes
Peyto Energy Trust
Notes to Consolidated Financial Statements
September 30, 2005 and 2004
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 2004 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.
Measurement uncertainty
The amount recorded for depletion and depreciation of property, plant
and equipment, the asset retirement obligation, the ceiling test
calculation and reserve based bonus 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.
2. Property, Plant and Equipment
---------------------------------------------------------------------
September 30, December 31,
2005 2004
---------------------------------------------------------------------
$ $
---------------------------------------------------------------------
Property, plant and equipment 868,033,495 616,422,327
Accumulated depletion and depreciation (126,576,433) (85,180,541)
---------------------------------------------------------------------
741,457,062 531,241,786
---------------------------------------------------------------------
---------------------------------------------------------------------
At September 30, 2005 costs of $28,663,020 (December 31, 2004 -
$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 $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.
4. Unitholders' Capital
Authorized: Unlimited number of voting trust units
Issued and Outstanding
---------------------------------------------------------------------
Number of Amount
Trust Units 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 - (7,671,305)
Trust units issued pursuant to DRIP 145,305 4,085,186
---------------------------------------------------------------------
Balance, September 30, 2005 101,993,139 320,956,420
---------------------------------------------------------------------
---------------------------------------------------------------------
Units to be Issued
The Trust implemented a Distribution Reinvestment Plan ("DRIP")
effective for the March 2005 distribution. The DRIP provides eligible
holders of trust units of Peyto the opportunity to accumulate
additional trust units by reinvesting their cash distributions paid
by Peyto. The cash distributions are reinvested at the discretion of
Peyto, either by acquiring trust units issued from treasury at a 5%
discount to the average market price or by acquiring trust units at
prevailing market rates. On October 14, 2005, 38,219 trust units were
issued from treasury at a price of $29.06 per trust unit pursuant to
the Plan.
Per Unit Amounts
Earnings per unit have been calculated based upon the weighted
average number of units outstanding during the period of 98,584,597
(2004 - 91,450,544; restated for 2 for 1 split of trust units May 31,
2005). There are no dilutive instruments outstanding.
5. 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 nine month period ended September 30, 2005, the Trust paid
distributions to the unitholders in the aggregate amount of
$99.9 million (2004 - $67.2 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
(x) Note: prior period restated for 2 for 1 split of trust units
completed May 31, 2005.
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 Nine Months ended
September 30 September 30
2005 2004 2005 2004
$ $ $ $
---------------------------------------------------------------------
Field expenses 5,192,013 2,950,973 13,249,653 8,203,264
Processing and
gathering income (1,654,626) (1,036,148) (4,696,684) (2,946,536)
---------------------------------------------------------------------
Total operating
costs 3,537,387 1,914,825 8,552,969 5,256,728
---------------------------------------------------------------------
---------------------------------------------------------------------
7. 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
September 30, 2005 is as follows:
Crude Oil Price
Period Hedged Type Daily Volume (CAD)
---------------------------------------------------------------------
October 1 to December 31, 2005 Fixed price 300 bbl $54.35/bbl
October 1 to December 31, 2005 Fixed price 250 bbl $57.52/bbl
October 1 to December 31, 2005 Fixed price 200 bbl $52.07/bbl
October 1 to December 31, 2005 Fixed price 200 bbl $53.15/bbl
October 1 to December 31, 2005 Fixed price 200 bbl $55.20/bbl
October 1 to December 31, 2005 Fixed price 200 bbl $60.50/bbl
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)
---------------------------------------------------------------------
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.71/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.70/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.80/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.45/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.55/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.70/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $7.00/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $7.27/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.42/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.65/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.80/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.90/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $7.01/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $7.11/GJ
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
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 $10.28/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $10.06/GJ
As at September 30, the Trust had committed to the future sale of
479,300 barrels of crude oil at an average price of $64.89 per barrel
and 25,830,000 gigajoules (GJ) of natural gas at an average price of
$8.08 per GJ or $9.45 per mcf based on the historical heating value
of Peyto's natural gas. These contracts will generate revenue
totaling $239.7 million. Based on the market's estimate of the future
commodity prices as at September 30, 2005 the fair value of these
contracts would be $342.1 million.
Subsequent to September 30, 2005 the Trust entered into the following
contracts:
Natural Gas Price
Period Hedged Type Daily Volume (CAD)
---------------------------------------------------------------------
April 1 to October 31, 2006 Fixed price 5,000 GJ $10.60/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $11.40/GJ
8. Supplemental Cash Flow Information
2005 2004
$ $
---------------------------------------------------------------------
Cash interest paid during the year 6,844,870 4,940,808
Cash taxes paid during the year 690,401 462,354
---------------------------------------------------------------------
---------------------------------------------------------------------
Peyto Exploration & Development Corp. Information
Officers
Don Gray Glenn Booth
President and Chief Executive Officer Vice President, Land
Ken Veres Sandra Brick
Vice-President, Exploration Vice President, Finance
Darren Gee Stephen Chetner
Vice President, Engineering Corporate Secretary
Scott Robinson Kathy Turgeon
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
