SYMBOL: PEY.UN - TSX
CALGARY, Nov. 8 /CNW/ - Peyto Energy Trust ("Peyto") is pleased to
present the operating and financial results for the third 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 $1.90/boe, three months ending September 30, 2006
- Low base general and administrative costs $0.55/boe, three months
ending September 30, 2006
- High revenue per boe - $43.90/boe ($7.32/mcfe) before hedging,
$50.05/boe ($8.34/mcfe) after hedging, three months ending
September 30, 2006
- High field netback - $36.58/boe, three months ending September 30,
2006
- High operatorship - we operate over 95% of our production
- Low cash distribution payout ratio - cash distributions were 57% of
funds from operations for the three months ended September 30, 2006
and 50% for the nine months year to date.
- Low debt to funds from operations ratio - 1.5 (net debt, before
provision for future compensation, divided by annualized third
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 $398 million issuing
units from treasury, accumulated earnings of $484 million, and
distributed $401 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
third quarter of 2006.
- Production growth - production increased 3% from 22,646 boe/d in the
third quarter of 2005 to 23,422 boe/d in the third quarter of 2006
- Production per unit - decreased 9% per trust unit from the third
quarter of 2005, after adjusting for debt and future unrealized
performance based compensation
- Per unit funds from operations - decreased 12% from the previous year
to $0.69/unit
- Hedging - we had a $13.2 million gain for the three months ending
September 30, 2006
- Capital expenditures - $71.2 million was invested into finding and
developing new natural gas reserves
- Distributions per unit increased by 17% from the third quarter of
2005 while the cash payout ratio remained low at 57% compared to 42%
in the third quarter of 2005. A total of $44.1 million or $0.42 per
unit was distributed to unitholders in the third quarter of 2006.
Natural gas volumes recorded in thousand cubic feet (mcf) are converted
to barrels of oil equivalent (boe) using the ratio of six (6) thousand
cubic feet to one (1) barrel of oil (bbl).
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3 Months Ended Sep 30 % 9 Months Ended Sep 30 %
2006 2005 Change 2006 2005 Change
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Operations
Production
Natural gas
(mcf/d) 115,304 108,460 6% 112,905 106,143 6%
Oil & NGLs
(bbl/d) 4,205 4,569 (8)% 4,164 4,520 (8)%
Barrels of
oil
equivalent
(boe/d (at)
6:1) 23,422 22,646 3% 22,982 22,211 3%
Product prices
Natural gas
($/mcf) 7.81 8.67 (10)% 8.33 8.17 2%
Oil & NGLs
($/bbl) 64.50 57.22 13% 62.89 54.56 15%
Operating expenses
($/boe) 1.90 1.70 12% 1.99 1.41 41%
Transportation
($/boe) 0.58 0.66 (12)% 0.60 0.67 (10)%
Field netback
($/boe) 36.58 38.39 (5)% 38.72 35.98 8%
General &
administrative
expenses ($/boe) 0.55 0.13 323% 0.35 0.10 250%
Interest expense
($/boe) 2.52 1.16 117% 1.97 1.13 74%
Financial ($000,
except per unit)
Revenue 107,844 110,566 (2)% 328,313 304,062 8%
Royalties
(net of ARTC) 23,680 25,654 (8)% 69,175 73,280 (6)%
Funds from
operations 72,360 77,179 (6)% 228,485 210,363 9%
Funds from
operations
per unit 0.69 0.78 (12)% 2.17 2.16 0%
Total
distributions 44,111 35,505 24% 129,549 99,875 30%
Total
distributions
per unit 0.42 0.36 17% 1.24 1.025 21%
Payout ratio 61 46 35% 57 47 21%
Cash distributions
(net of DRIP) 41,019 32,318 27% 113,999 93,323 22%
Payout ratio 57 42 33% 50 44 14%
Earnings 46,155 37,702 22% 148,216 100,823 47%
Earnings per
diluted unit 0.44 0.38 16% 1.42 1.04 37%
Capital
expenditures 71,223 93,001 (23)% 283,513 250,806 13%
Weighted average
trust units
outstanding 104,924,702 98,584,597 6% 104,554,325 97,372,966 7%
As at September 30
Net debt
(before future
compensation
expense) 431,097 207,225 108%
Unitholders'
equity 481,863 362,858 33%
Total assets 1,110,547 885,464 25%
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3 Months Ended 9 Months Ended
Sep 30 Sep 30
2006 2005 2006 2005
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Net Earnings 46,155 37,702 148,216 100,823
Items not requiring cash:
Non-cash provision for
(recovery of) performance
based compensation (2,005) 14,143 192 39,188
Future income tax expense 7,821 11,056 19,376 28,786
Depletion, depreciation
and accretion 20,389 14,278 60,701 41,566
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Funds from operations(1) 72,360 77,179 228,485 210,363
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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
During the third quarter, Peyto invested $71.2 million into designing,
drilling and building new producing gas assets in the deep basin. Drilling and
completions accounted for $51.5 million while wellsite equipment, pipelines
and gas plants accounted for $18.3 million. Acquisition of new land and
seismic made up the balance or $1.4 million. So far in 2006, we have now
invested $24.7 million building new gas plants in the Wildhay and Nosehill
areas. These plants have added 40 mmcf/d of processing capacity.
In the third quarter, the company drilled and cased 19 gross (14.9 net)
gas wells and completed 41 gross (37.6 net) gas zones. Average production
increased 530 boe/d from 22,892 boe/d in the second quarter to 23,422 boe/d in
the third quarter as 37 gross (31.3 net) new gas zones were tied in and
brought on production. Our operating costs were $1.90/boe for the third
quarter and $1.99/boe for the year to date. We continue to be one of the
lowest cost producers of natural gas in North America. Royalties for the
period were 22% or $10.99/boe.
Peyto's marketing strategy continues to provide significant short term
price security. For the third quarter the average gas price was $7.81/mcf and
the average liquids price was $64.50/bbl. The combination of our high quality
production and our low operating costs yielded very strong field netbacks of
$36.58/boe. Marketing for the third quarter of 2006 resulted in a gain of
$13.2 million and increased the combined gas and liquids price by $6.14/boe.
For the first nine months of 2006, Peyto's marketing strategy has resulted in
a gain of $18.5 million as compared to the $17.2 million loss for the prior
period, therefore achieving our objective of smoothing out short term
fluctuations in the price of both natural gas and natural gas liquids.
Activity Update
To date in 2006, Peyto has drilled 78 gross (61 net) wells and brought on
production 124 gross (105.4 net) gas zones. Current production is 22,850 boe/d
and continues to stabilize as our production base matures. We have
significantly reduced our activity level reflecting our plan to fund our
opportunities with cash flow after distributions. We plan to utilize between
one and two drilling rigs throughout the fourth quarter.
Marketing
Short term gas prices have softened due to record storage levels and the
lack of any meaningful weather events. The October AECO monthly gas price
reached a four year low of $4.22/GJ. Although the forecast for this winter's
gas price has softened, the long term price for natural gas has remained
resilient. The future price for the period November 2009 to December 2010 has
actually improved 9% from $6.73/GJ a year ago to $7.31/GJ. Peyto's long life
reserves position the trust to capture this long term strength in gas prices.
Consistent with our marketing strategy, Peyto has commitment to forward
sell 255,800 barrels of crude oil at an average price of $83.29 per barrel and
15,640,000 gigajoules (GJ) of natural gas at an average price of $9.20 per GJ
or $10.77 per mcf. If we realize the market's estimate for future commodity
prices, as at September 30, 2006, this forward sale represents a 38% price
premium. For this winter's heating season, Peyto has forward sold
approximately two thirds of our net of royalty gas volume at $9.61/GJ or
$11.24/mcf.
Proposed Tax Legislation
On October 31, 2006, the Federal Government announced tax proposals
pertaining to taxation of distributions paid by Trusts and the personal tax
treatment of Trust distributions. Currently, Peyto does not pay tax on
distributions as tax is paid by the unitholders. The proposals would result in
a two-tiered tax structure similar to that of corporations whereby
distributions would be subject to a 31.5 per cent tax at the Trust level and
tax equivalent to that of a taxable dividend at the individual level. At
present, Canadian Pension Funds, Registered Retirement Savings Plans and
Registered Retirement Income Funds ("Canadian Tax Exempt Entities") are not
subject to tax on Trust distributions. Under the proposals, those Canadian Tax
Exempt Entities would be subject to tax as a result of the tax imposed at the
Trust level. The proposals would also increase the tax for non-resident
unitholders due to the tax imposed at the Trust level. If enacted, the
proposed plan would apply to Peyto effective January 1, 2011. We are currently
assessing the proposals and the potential implications to the Trust.
On behalf of our unitholders, Peyto is disappointed with the proposed
changes to the Canadian government's treatment of income trusts. However, we
know the Trust is well positioned to handle whatever changes do occur. Peyto
is and always has been a finder and developer of gas assets. A high portion of
our cash flow is re-invested into this ongoing enterprise and therefore
generates Canadian Exploration and Development Expense that can be used to
offset tax on income. Our Trust model provides the flexibility to fund this
business strategy with cash flow, bank lines or equity depending on which is
most efficient for our unitholders.
Outlook
Earlier in the year we established a strategy to "live within our means"
with the expectation that it would result in improved capital efficiencies and
allow our total production base to stabilize faster as we slow down the pace
at which we add new production. This strategy is working. These two factors
mean we will require less capital to maintain our production and grow our
reserves. The current distribution is well balanced with our business needs
and there are no plans to decrease our distribution in the foreseeable future.
Peyto's technical team continues to generate drilling opportunities that yield
high return on capital invested and our superior assets continue to internally
fund those investment ideas. 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 third quarter results on Thursday,
November 9, 2006 at 9:00 a.m. Mountain Standard Time (MST), 11:00 a.m. Eastern
Standard Time (EST). To participate, please call 1-416-644-3425 (Toronto area)
or 1-866-250-4909 for all other participants. The conference call will also be
available on replay by calling 1-416-640-1917 (Toronto area) or 1-877-289-8525
for all other parties, using passcode 21206618 followed by the pound key. The
replay will be available at 11:00 a.m. MST, 1:00 p.m. EST Thursday,
November 9, 2006 until midnight EST on Thursday, November 16, 2006. The
conference call can also be accessed through the internet at
http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID(equal sign)1626900.
<<
Don T. Gray Darren Gee
Chief Executive Officer President
November 8, 2006
>>
Certain information set forth in this document and Management's
Discussion and Analysis, including management's assessment of Peyto's future
plans and operations, contains forward-looking statements. By their nature,
forward-looking statements are subject to numerous risks and uncertainties,
some of which are beyond these parties' control, including the impact of
general economic conditions, industry conditions, volatility of commodity
prices, currency fluctuations, imprecision of reserve estimates, environmental
risks, competition from other industry participants, the lack of availability
of qualified personnel or management, stock market volatility and ability to
access sufficient capital from internal and external sources. Readers are
cautioned that the assumptions used in the preparation of such information,
although considered reasonable at the time of preparation, may prove to be
imprecise and, as such, undue reliance should not be placed on forward-looking
statements. Peyto's actual results, performance or achievement could differ
materially from those expressed in, or implied by, these forward-looking
statements and, accordingly, no assurance can be given that any of the events
anticipated by the forward-looking statements will transpire or occur, or if
any of them do so, what benefits 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 September 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").
This MD&A was prepared using information that is current as of November 7,
2006. Additional information about Peyto, including the most recently filed
annual information form is available at www.sedar.com.
As further described in Note 1 to the Consolidated Interim Financial
Statements, the Trust has determined that certain adjustments are required to
restate the Consolidated Interim Statement of Cash Flows for the three month
period ended March 31, 2006. The Trust has determined that it incorrectly
classified the reduction in accounts payable attributable to the payment of
the market based and reserves based performance based compensation in cash
flows from investing activities instead of cash flows from operating
activities. The restatement decreased net cash provided by operating
activities and decreased net cash used in investing activities by
$56.2 million. The correction of the error did not impact the Consolidated
Interim Balance Sheets or the Consolidated Interim Statements of Earnings and
Accumulated Earnings for the three months ended March 31, 2006 and the three
and six months ended June 30, 2006 or the Consolidated Interim Statement of
Cash Flows for the three months ended June 30, 2006.
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 22 percent, well below the level that would jeopardize
Peyto's status as a mutual fund trust under current legislation.
Proposed Tax Legislation
On October 31, 2006, the Federal Government announced tax proposals
pertaining to taxation of distributions paid by Trusts and the personal tax
treatment of Trust distributions. Currently, Peyto does not pay tax on
distributions as tax is paid by the unitholders. The proposals would result in
a two-tiered tax structure similar to that of corporations whereby
distributions would be subject to a 31.5 per cent tax at the Trust level and
tax equivalent to that of a taxable dividend at the individual level. At
present, Canadian Pension Funds, Registered Retirement Savings Plans and
Registered Retirement Income Funds ("Canadian Tax Exempt Entities") are not
subject to tax on Trust distributions. Under the proposals, those Canadian Tax
Exempt Entities would be subject to tax as a result of the tax imposed at the
Trust level. The proposals would also increase the tax for non-resident
unitholders due to the tax imposed at the Trust level. If enacted, the
proposed plan would apply to Peyto effective January 1, 2011. We are currently
assessing the proposals and the potential implications to the Trust.
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
($000 except per
unit amounts) Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4
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Total revenue
(net of
royalties) 84,164 88,515 86,459 94,111 84,912 73,473 72,397 66,024
Funds from
operations 72,360 77,507 78,617 86,607 77,179 66,548 66,636 60,334
Per unit -
basic(x) 0.69 0.74 0.76 0.85 0.78 0.69 0.69 0.65
Per unit -
diluted(x) 0.69 0.74 0.76 0.85 0.78 0.69 0.69 0.65
Earnings (loss) 46,155 56,768 45,293 60,745 37,702 25,690 37,431 (2,558)
Per unit -
basic(x) 0.44 0.54 0.44 0.60 0.38 0.27 0.39 (0.03)
Per unit -
diluted(x) 0.44 0.54 0.44 0.60 0.38 0.27 0.39 (0.03)
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(x) Note: prior periods restated for 2 for 1 split of trust units
completed May 31, 2005.
RESULTS OF OPERATIONS
Production
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Three Months Ended Nine Months Ended
Sep 30 Sep 30
2006 2005 2006 2005
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Natural gas (mmcf/d) 115.3 108.5 112.9 106.1
Oil & natural gas liquids (bbl/d) 4,205 4,569 4,164 4,520
Barrels of oil equivalent (boe/d) 23,422 22,646 22,982 22,211
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Natural gas production averaged 115.3 mmcf/d in the third quarter of 2006,
6 percent higher than the 108.5 mmcf/d reported for the same period in 2005.
Oil and natural gas liquids production averaged 4,205 bbl/d, a decrease of 8
percent from 4,569 bbl/d reported in the prior year. Year to date production
increased 3 percent from 22,211 boe/d to 22,982 boe/d. The overall production
increases are directly attributable to Peyto's ongoing drilling program
offsetting natural production declines.
Commodity Prices
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Three Months Ended Nine Months Ended
Sep 30 Sep 30
2006 2005 2006 2005
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Natural gas ($/mcf) 6.53 10.00 7.64 8.60
Hedging - gas ($/mcf) 1.28 (1.33) 0.69 (0.43)
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Natural gas - after hedging ($/mcf) 7.81 8.67 8.33 8.17
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Oil and natural gas liquids($/bbl) 65.29 62.73 65.38 58.48
Hedging - oil ($/bbl) (0.79) (5.51) (2.49) (3.92)
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Oil and natural gas liquids -
after hedging ($/bbl) 64.50 57.22 62.89 54.56
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Total Hedging ($/boe) 6.14 (7.47) 2.95 (2.84)
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Our natural gas price before hedging averaged $6.53/mcf during the third
quarter of 2006, a decrease of 35 percent from $10.00/mcf reported for the
equivalent period in 2005. Oil and natural gas liquids prices averaged
$65.29/bbl up 4 percent from $62.73/bbl a year earlier. Hedging activity for
the third quarter of 2006 accounted for $6.14/boe of Peyto's price achieved.
Revenue
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Three Months Ended Nine Months Ended
Sep 30 Sep 30
($000) 2006 2005 2006 2005
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Natural gas 69,347 99,769 235,500 249,099
Oil and natural gas liquids 25,259 26,370 74,324 72,173
Hedging gain (loss) 13,238 (15,573) 18,489 (17,210)
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Total revenue 107,844 110,566 328,313 304,062
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For the three months ended September 30, 2006, gross revenue decreased
2 percent to $107.8 million from $110.6 million for the same period in 2005.
The decrease in revenue for the period was a result of weaker commodity prices
for gas and decreased production volumes for oil and NGL. These declines were
offset by increased production volumes for gas and increased commodity prices
for liquids, as detailed in the following table.
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Three Months ended Sep 30 Nine Months ended Sep 30
2006 2005 $million 2006 2005 $million
-------------------------------------------------------------------------
Total Revenue,
Sep 30, 2005 110.6 304.1
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Revenue change
due to:
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Natural gas
Volume
(mmcf) 10,608.0 9,978.3 5.4 30,823 28,977 15.1
Price
($/mcf) $7.81 $8.67 (9.1) $8.33 $8.17 4.9
Oil & NGL
Volume
(mbbl) 387 420 (1.9) 1,137 1,234 (5.3)
Price
($/bbl) $64.50 $57.22 2.8 $62.89 $54.56 9.5
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Total Revenue,
Sep 30, 2006 107.8 328.3
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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 Nine Months Ended
Sep 30 Sep 30
2006 2005 2006 2005
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Royalties, net of ARTC ($000) 23,680 25,654 69,175 73,280
% of sales 22 23 21 24
$/boe 10.99 12.31 11.03 12.09
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For the third quarter of 2006, royalties averaged $10.99/boe or
approximately 22 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. It is
management's expectation that royalties as a percentage of sales for future
periods will remain at or near current 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 Nine Months Ended
Sep 30 Sep 30
2006 2005 2006 2005
-------------------------------------------------------------------------
Operating costs ($000)
Field expenses 6,245 5,192 18,404 13,250
Processing and gathering income (2,161) (1,655) (5,939) (4,697)
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Total operating costs 4,084 3,537 12,465 8,553
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$/boe 1.90 1.70 1.99 1.41
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Transportation 1,256 1,384 3,767 4,087
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$/boe 0.58 0.66 0.60 0.67
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Operating costs were $4.1 million in the third quarter of 2006 compared to
$3.5 million during the same period a year earlier. On a unit of production
basis, operating costs averaged $1.90/boe in the third quarter of 2006
compared to $1.70/boe for the third quarter of 2005. The increased cost is
attributable to year-over-year inflationary effects. Transportation expense
remained constant and was lower on a per boe basis.
Netbacks
Operating netbacks represent the profit margin associated with the
production and sale of petroleum and natural gas. The primary factors that
produce Peyto's strong netbacks are a low cost structure and the high heat
content of our natural gas that results in higher commodity prices.
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Three Months Ended Nine Months Ended
Sep 30 Sep 30
($/boe) 2006 2005 2006 2005
-------------------------------------------------------------------------
Sale Price 50.05 53.06 52.34 50.15
Less:
Royalties 10.99 12.31 11.03 12.09
Operating costs 1.90 1.70 1.99 1.41
Transportation 0.58 0.66 0.60 0.67
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Operating netback 36.58 38.39 38.72 35.98
General and administrative 0.55 0.13 0.35 0.10
Interest on long-term debt 2.52 1.16 1.97 1.13
Capital tax - 0.06 - 0.06
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Cash netback 33.51 37.04 36.40 34.69
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General and Administrative Expenses
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
Sep 30 Sep 30
2006 2005 2006 2005
-------------------------------------------------------------------------
G&A expenses ($000) 2,556 1,620 6,971 4,560
Overhead recoveries (1,362) (1,356) (4,762) (3,976)
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Net G&A expenses 1,194 264 2,209 584
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$/boe 0.55 0.13 0.35 0.10
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General and administrative expenses before overhead recoveries increased
to $2.6 million in the third quarter of 2006, as compared to $1.6 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 $0.55 per boe. Peyto has decreased reliance
on third party consulting and replaced these services with staff positions
resulting in increased general and administrative costs. This strategy has
resulted in an over-all cost decrease to the Trust.
Interest Expense
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
Sep 30 Sep 30
2006 2005 2006 2005
-------------------------------------------------------------------------
Interest expense ($000) 5,432 2,422 12,374 6,845
$/boe 2.52 1.16 1.97 1.13
-------------------------------------------------------------------------
Third quarter 2006 interest expense was $5.4 million or $2.52/boe compared
to $2.4 million or $1.16/boe a year earlier. During 2006, average debt levels
have increased to partially fund Peyto's capital expenditure program and
interest rates on our long debt have increased year over year. Interest rates
continue to be favourable and are not expected to increase substantially in
the short term.
Depletion, Depreciation and Accretion
The 2006 third quarter provision for depletion, depreciation and accretion
totaled $20.4 million as compared to $14.3 million in 2005. On a unit of
production basis, depletion, depreciation and accretion costs averaged
$9.46/boe as compared to $6.85/boe in the third quarter of 2005. Year to date
depletion, depreciation and accretion totaled $60.7 million in 2006 compared
to $41.6 million in 2005 or $9.67/boe compared to $6.86/boe. 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 $19.3 million for
the first three quarters of 2006 from $28.8 million for the same period in
2005. This decrease is primarily due to increased capital activity year over
year generating higher tax pools and a reduction in federal and provincial
income tax rates being phased in over the next four years. At September 30,
2006 the Trust has tax pools of approximately $672.6 million (December 31,
2005 - $582.4 million) available for deduction against future income.
MARKETING
Commodity Price Risk Management
The Trust is a party to certain off balance sheet derivative financial
instruments, including fixed price contracts. The Trust enters into these
contracts with well established counter-parties for the purpose of protecting
a portion of its future revenues from the volatility of oil and natural gas
prices. During the third quarter of 2006, we recorded a hedging gain of
$13.2 million as compared to a hedging loss of $15.6 million in the third
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)
-------------------------------------------------------------------------
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
Nov. 1, 2006 to Nov 30, 2006 Fixed price 5,000 GJ $5.76/GJ
Dec. 1, 2006 to Dec 31, 2006 Fixed price 5,000 GJ $7.28/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 $7.25/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $7.51/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $7.50/GJ
April 1, 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 the degree to which we are sensitive to changes in
commodity prices.
Currency Risk Management
The Trust is exposed to fluctuations in the Canadian/US dollar exchange
ratio since our natural gas and oil sales are effectively priced in US dollars
and converted to Canadian dollars. In the short term, this risk is mitigated
indirectly as a result of our commodity hedging strategy as we hedge in
Canadian currency. Over the long term, the Canadian dollar tends to rise as
oil prices rise. There is a similar correlation between oil and gas prices.
Currently we have not entered into any agreements to further manage this
specific risk.
Interest Rate Risk Management
The Trust is exposed to interest rate risk in relation to interest expense
on its revolving demand facility. Currently we have not entered into any
agreements to manage this risk. At September 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 $3.4 million per
annum.
LIQUIDITY AND CAPITAL RESOURCES
Funds from Operations
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
Sep 30 Sep 30
($000) 2006 2005 2006 2005
-------------------------------------------------------------------------
Net earnings 46,155 37,702 148,216 100,823
Items not requiring cash:
Non-cash provision for
performance based compensation (2,005) 14,143 192 39,188
Future income tax expense 7,821 11,056 19,376 28,786
Depletion, depreciation &
accretion 20,389 14,278 60,701 41,566
-------------------------------------------------------------------------
Funds from operations 72,360 77,179 228,485 210,363
-------------------------------------------------------------------------
For the three months ended September 30, 2006, funds from operations
totaled $72.4 million or $0.69 per unit, representing a 6 percent decrease
from the $77.2 million, or $0.78 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 third quarter of 2006 was 4.84% (2005 - 4.04%).
At September 30, 2006, $400 million was drawn under the facility. Working
capital liquidity is maintained by drawing from and repaying the unutilized
credit facility as needed. At September 30, 2006, we had a working capital
deficit of $41.4 million.
We believe that funds generated from our operations, together with
borrowings under our credit facility 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 available cash
flow.
Capital
Peyto implemented a Distribution Reinvestment Plan ("DRIP") effective with
the March 2005 distribution whereby eligible unitholders may elect to reinvest
their monthly cash distributions in additional trust units at a 5% discount to
market price. On November 21, 2005 the DRIP plan was amended to incorporate an
Optional Trust Unit Purchase Plan ("OTUPP") which provides unitholders
enrolled in the DRIP with the opportunity to purchase additional trust units
from treasury using the same pricing as the DRIP. Both the DRIP and the OTUPP
were suspended effective August 31, 2006. At this time the Board is not
considering issuing any equity under current market conditions.
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 690,387 16,300,613
Trust units issued pursuant to OTUPP 833,220 19,018,693
-------------------------------------------------------------------------
Balance, September 30, 2006 105,251,394 398,433,829
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 as final compensation is based on third party year end
reserve data. A provision for the reserve value based component of
$1.1 million was recorded for the first nine months 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 September 30, 2006, compensation costs recovered related
to 4.3 million non-vested rights, with an average grant price of $22.71, total
$0.9 million. The Trust records a non-cash provision for future compensation
expense over the life of the rights. The cumulative provision totals
$9.2 million of which a recovery of $3.1 million was recorded in the three
months ending September 30, 2006.
Capital Expenditures
Net capital expenditures for the third quarter of 2006 totaled
$71.2 million. Exploration and development related activity represented
$52.9 million or 74% of the total, while expenditures on facilities, gathering
systems and equipment totaled $18.3 million or 26% of the total. The following
table summarizes capital expenditures for the quarter.
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
Sep 30 Sep 30
($000) 2006 2005 2006 2005
-------------------------------------------------------------------------
Land 575 3,300 13,253 8,592
Seismic 790 5,749 8,361 8,251
Drilling - Exploratory &
Development 51,489 70,274 204,808 190,171
Production Equipment,
Facilities & Pipelines 18,351 13,483 56,925 43,576
Acquisitions & Dispositions - - - -
Office Equipment 18 195 166 216
-------------------------------------------------------------------------
Total Capital Expenditures 71,223 93,001 283,513 250,806
-------------------------------------------------------------------------
Distributions
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
Sep 30 Sep 30
2006 2005 2006 2005
-------------------------------------------------------------------------
Funds from operations ($000) 72,360 77,179 227,485 210,363
Total distributions ($000) 44,111 35,505 129,549 99,875
Total distributions per
unit ($)(x) 0.42 0.36 1.24 1.025
Payout ratio (%) 61 46 57 47
Cash distributions ($000)
(net of DRIP) 41,019 32,318 113,999 93,323
Payout ratio (%) 57 42 50 44
-------------------------------------------------------------------------
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 was
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 238,371
2007 953,484
2008 1,096,641
2009 1,096,641
2010 1,096,641
2011 1,096,641
-------------------------------------------------------------------------
5,578,419
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 participated in a joint
venture capital project with a company whose director was also a Peyto
director until May 16, 2006. The Trust's participation in this joint venture
amounted to $620,218. Costs associated with this joint venture capital project
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
nine months of 2006, the accrued and actual legal fees due to the law firm
totaled $439,485.
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 2006, the Trust paid distributions to the
unitholders in the amount of $129.5 million (2005 - $99.9 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
July 2006 July 31, 2006 August 15, 2006 $0.14
August 2006 August 31, 2006 September 15, 2006 $0.14
September 2006 September 30, 2006 October 13, 2006 $0.14
>>
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
Q3 Q2 Q1
-------------------------------------------------------------------------
Operations
Production
Natural gas (mcf/d) 115,304 112,484 110,878
Oil & NGLs (bbl/d) 4,205 4,145 4,143
Barrels of oil equivalent
(boe/d (at) 6:1) 23,422 22,892 22,622
Average product prices
Natural gas ($/mcf) 7.81 7.96 9.26
Oil & natural gas liquids ($/bbl) 64.50 66.94 57.12
Average operating expenses ($/boe) 1.90 2.26 1.81
Average transportation costs ($/boe) 0.58 0.59 0.63
Field netback ($/boe) 36.58 39.64 40.02
General & administrative expense
($/boe) 0.55 0.43 0.06
Interest expense ($/boe) 2.52 2.00 1.36
Financial ($000 except per unit)
Revenue 107,844 106,751 113,717
Royalties (net of ARTC) 23,680 18,236 27,258
Funds from operations 72,360 77,507 78,617
Funds from operations per unit(x) 0.69 0.74 0.76
Total distributions 44,111 43,921 41,517
Total distributions per unit(x) 0.42 0.42 0.40
Payout ratio 61% 57% 53%
Cash distributions (net of DRIP) 41,019 38,315 34,665
Payout ratio 57% 49% 44%
Earnings 46,155 56,768 45,293
Earnings per diluted unit(x) 0.44 0.54 0.44
Capital expenditures 71,223 67,195 145,094
Weighted average trust units
outstanding(x) 104,924,702 104,472,570 103,910,640
-------------------------------------------------------------------------
2005
Q4 Q3 Q2
-------------------------------------------------------------------------
Operations
Production
Natural gas (mcf/d) 108,356 108,460 106,866
Oil & NGLs (bbl/d) 4,185 4,569 4,653
Barrels of oil equivalent
(boe/d (at) 6:1) 22,245 22,646 22,464
Average product prices
Natural gas ($/mcf) 10.55 8.67 8.00
Oil & natural gas liquids ($/bbl) 58.43 57.22 51.03
Average operating expenses ($/boe) 1.95 1.70 1.30
Average transportation costs ($/boe 0.70 0.66 0.68
Field netback ($/boe) 43.33 38.39 33.97
General & administrative expense
($/boe) 0.05 0.13 0.10
Interest expense ($/boe) 0.91 1.16 1.25
Financial ($000 except per unit)
Revenue 127,633 110,566 99,427
Royalties (net of ARTC) 33,522 25,654 25,954
Funds from operations 86,607 77,179 66,548
Funds from operations per unit(x) 0.85 0.78 0.69
Total distributions 36,773 35,505 33,898
Total distributions per unit(x) 0.36 0.36 0.35
Payout ratio 42% 46% 51%
Cash distributions (net of DRIP) 33,771 32,318 31,023
Payout ratio 39% 42% 47%
Earnings 60,745 37,702 25,690
Earnings per diluted unit(x) 0.60 0.38 0.27
Capital expenditures 107,647 93,001 58,730
Weighted average trust units
outstanding(x) 102,148,411 98,584,597 96,848,988
(x)Note: prior periods restated for 2 for 1 split of trust units
completed May 31, 2005.
Peyto Energy Trust
Consolidated Balance Sheets
($000)
(unaudited)
September 30, December 31,
2006 2005
$ $
-------------------------------------------------------------------------
Assets
Current
Cash 6,287 -
Accounts receivable 44,916 82,794
Due from private placements - 27,450
Prepaid expenses and deposits 2,762 1,796
-------------------------------------------------------------------------
53,965 112,040
Property, plant and equipment (Note 2) 1,056,582 832,887
-------------------------------------------------------------------------
1,110,547 944,927
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities and Unitholders' Equity
Current
Accounts payable and accrued liabilities 70,328 208,284
Capital taxes payable - 111
Cash distributions payable 14,735 11,530
Provision for future performance based
compensation 10,319 8,748
-------------------------------------------------------------------------
95,382 228,673
-------------------------------------------------------------------------
Long-term debt (Note 3) 400,000 180,000
Provision for future performance based
compensation 22 1,401
Asset retirement obligations 5,611 4,729
Future income taxes 127,669 108,293
-------------------------------------------------------------------------
533,302 294,423
-------------------------------------------------------------------------
Unitholders' equity
Unitholders' capital (Note 4) 398,434 328,736
Units to be issued (Note 4) - 28,332
Accumulated earnings 484,142 335,926
Accumulated distributions (Note 5) (400,713) (271,163)
-------------------------------------------------------------------------
481,863 421,831
-------------------------------------------------------------------------
1,110,547 944,927
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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
($000 except per unit amounts)
(unaudited)
Three Months Ended Nine Months Ended
September 30 September 30
2006 2005 2006 2005
$ $ $ $
-------------------------------------------------------------------------
Revenue
Petroleum and natural
gas sales, net 84,164 84,912 259,138 230,782
-------------------------------------------------------------------------
Expenses
Operating (Note 6) 4,084 3,537 12,465 8,553
Transportation 1,256 1,384 3,767 4,087
General and administrative
(Note 7) 1,194 264 2,209 584
Future market and
reserves based bonus
provision (2,005) 14,144 192 39,188
Interest 5,432 2,422 12,374 6,845
Depletion, depreciation
and accretion (Note 2) 20,389 14,278 60,701 41,566
-------------------------------------------------------------------------
30,350 36,029 91,708 100,823
-------------------------------------------------------------------------
Earnings before taxes 53,814 48,883 167,430 129,959
-------------------------------------------------------------------------
Taxes
Future income tax
expense 7,821 11,056 19,376 28,786
Capital tax expense (162) 125 (162) 350
-------------------------------------------------------------------------
7,659 11,181 19,214 29,136
-------------------------------------------------------------------------
Net earnings for the
period 46,155 37,702 148,216 100,823
Accumulated earnings,
beginning of period 437,987 237,479 335,926 174,358
-------------------------------------------------------------------------
Accumulated earnings,
end of period 484,142 275,181 484,142 275,181
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per unit (Note 4)
Basic 0.44 0.38 1.42 1.04
Diluted 0.44 0.38 1.42 1.04
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
Peyto Energy Trust
Consolidated Statements of Cash Flows
($000)
(unaudited)
Three Months Ended Nine Months Ended
September 30 September 30
2006 2005 2006 2005
$ $ $ $
(restated
see Note 1)
-------------------------------------------------------------------------
Cash provided by (used in)
Operating Activities
Net earnings for the
period 46,155 37,702 148,216 100,823
Items not requiring cash:
Future income tax expense 7,821 11,056 19,376 28,786
Depletion, depreciation
and accretion 20,389 14,278 60,701 41,566
Change in non-cash working
capital related to
operating activities (6,166) 8,273 (34,884) 9,427
-------------------------------------------------------------------------
68,199 71,309 193,409 180,602
-------------------------------------------------------------------------
Financing Activities
Issue of trust units,
net of costs and DRIP 8,748 145,079 25,815 149,509
Cash distributions paid
(net of DRIP) (41,019) (32,318) (113,999) (93,323)
Increase in bank debt 10,000 (60,000) 220,000 40,000
Change in non-cash
working capital related
to financing activities 1,390 501 30,656 29,141
-------------------------------------------------------------------------
(20,881) 53,262 162,472 125,327
-------------------------------------------------------------------------
Investing Activities
Additions to property,
plant and equipment (71,223) (93,001) (283,513) (250,806)
Change in non-cash
working capital related
to investing activities 26,353 28,788 (66,081) 11,651
-------------------------------------------------------------------------
(44,870) (64,213) (349,594) (239,155)
-------------------------------------------------------------------------
Net increase (decrease)
in cash 2,448 60,358 6,287 66,774
Cash, beginning of period 3,839 6,416 - -
-------------------------------------------------------------------------
Cash, end of period 6,287 66,774 6,287 66,774
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Peyto Energy Trust
Notes to Consolidated Financial Statements
($000 except per unit amounts)
(unaudited)
September 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.
Correction of Error
The Consolidated Interim Statements of Cash Flows for the three
months ended March 31, 2006 and the six months ended June 30, 2006
have been restated. The Trust has determined that it incorrectly
classified the reduction in accounts payable attributable to the
payment of the market based and reserves based performance based
compensation in cash flows from investing activities instead of cash
flows from operating activities. The correction of the error did not
impact the Consolidated Interim Balance Sheets or the Consolidated
Interim Statements of Earnings and Accumulated Earnings for the three
months ended March 31, 2006 and the three and six months ended
June 30, 2006 or the Consolidated Interim Statement of Cash Flows for
the three months ended June 30, 2006.
The effect of the restatement in the Consolidated Interim Statements
of Cash Flows is as follows:
Three months ended March 31, 2006
---------------------------------------------------------------------
Change in
Non-Cash
As Previously Working As
Reported Capital Restated
---------------------------------------------------------------------
($000) $ $ $
---------------------------------------------------------------------
Change in non-cash working capital
related to operating activities 25,266 (56,252) (30,986)
Change in non-cash working capital
related to investing activities (75,912) 56,252 (19,660)
Cash provided by (used in)
Operating Activities 99,061 (56,252) 42,809
Investing Activities (221,007) 56,252 (164,755)
Six months ended June 30, 2006
---------------------------------------------------------------------
Change in
Non-Cash
As Previously Working As
Reported Capital Restated
---------------------------------------------------------------------
($000) $ $ $
---------------------------------------------------------------------
Change in non-cash working capital
related to operating activities 27,534 (56,252) (28,718)
Change in non-cash working capital
related to investing activities (148,686) 56,252 (92,434)
Cash provided by (used in)
Operating Activities 181,462 (56,252) 125,210
Investing Activities (360,976) 56,252 (304,724)
2. Property, Plant and Equipment
September December
30, 2006 31, 2005
($000) $ $
---------------------------------------------------------------------
Property, plant and equipment 1,260,139 976,005
Accumulated depletion and depreciation (203,557) (143,118)
---------------------------------------------------------------------
1,056,582 832,887
---------------------------------------------------------------------
---------------------------------------------------------------------
At September 30, 2006 costs of $39,032 (September 30, 2005 - $28,663)
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
Trust Units (no par value)
Number Amount
($000) of Units $
---------------------------------------------------------------------
Balance, December 31, 2004 47,725,272 138,953
Trust units issued by private placement 670,000 31,586
Trust unit issue costs - (103)
Trust units issued pursuant to DRIP 28,645 1,356
Trust units issued pursuant to 2 for 1 split 48,423,917 -
Trust units issued by public offering 5,000,000 152,750
Trust unit issue costs - (8,054)
Trust units issued pursuant to DRIP 279,561 7,448
Trust units issued pursuant to OTUPP 206,452 4,800
---------------------------------------------------------------------
Balance, December 31, 2005 102,333,847 328,736
Trust units issued by private placement 1,393,940 34,378
Trust units issued pursuant to DRIP 690,387 16,301
Trust units issued pursuant to OTUPP 833,220 19,019
---------------------------------------------------------------------
Balance, September 30, 2006 105,251,394 398,434
---------------------------------------------------------------------
---------------------------------------------------------------------
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. Both the DRIP and
OTUPP were suspended August 31, 2006.
Per Unit Amounts
Earnings per unit have been calculated based upon the weighted
average number of units outstanding during the period of 104,924,702
(2005 - 98,584,957). There are no dilutive instruments outstanding.
5. Accumulated Distributions
During the quarter, the Trust paid total distributions to unitholders
in the aggregate amount of $44.1 million of which $41.0 million was
settled in cash and $3.1 million was settled by the issuance of trust
units pursuant to the DRIP (2005 - total $35.5 million; cash $32.3
million and DRIP $3.2 million). For the nine months ended September
30, 2006, the Trusts paid total distributions to unitholders in the
aggregate amount of $129.5 million of which $114.0 million was
settled in cash and $15.5 million was settled by the issuance of
trust units pursuant to the DRIP (2005 - total $99.9 million; cash
$93.3 million and DRIP $6.6 million) in accordance with the following
schedule:
Production Record Distribution Per
Period Date Date Unit
---------------------------------------------------------------------
January 2006 January 31, 2006 February 15, 2006 $0.12
February 2006 February 28, 2006 March 15, 2006 $0.14
March 2006 March 31, 2006 April 13, 2006 $0.14
April 2006 April 30, 2006 May 15, 2006 $0.14
May 2006 May 31, 2006 June 15, 2006 $0.14
June 2006 June 30, 2006 July 14, 2006 $0.14
July 2006 July 31, 2006 August 15, 2006 $0.14
August 2006 August 31, 2006 September 15, 2006 $0.14
September 2006 September 30, 2006 October 13, 2006 $0.14
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 Nine Months
Ended Ended
September 30 September 30
2006 2005 2006 2005
($000) $ $ $ $
---------------------------------------------------------------------
Field expenses 6,245 5,192 18,404 13,250
Processing and gathering
income (2,161) (1,655) (5,939) (4,697)
---------------------------------------------------------------------
Total operating costs 4,084 3,537 12,465 8,553
---------------------------------------------------------------------
---------------------------------------------------------------------
7. General and Administrative Expenses
General and administrative expenses are reduced by operating and
capital overhead recoveries from operated properties.
Three Months Nine Months
Ended Ended
September 30 September 30
2006 2005 2006 2005
($000) $ $ $ $
---------------------------------------------------------------------
G&A expenses 2,556 1,620 6,971 4,560
Overhead recoveries (1,362) (1,356) (4,762) (3,976)
---------------------------------------------------------------------
Net G&A expenses 1,194 264 2,209 584
---------------------------------------------------------------------
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
September 30, 2006 is as follows:
Crude Oil
Average
Weighted
Daily Price
Period Hedged Type Volume (CAD)
---------------------------------------------------------------------
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
Average
Weighted
Daily Price
Period Hedged Type Volume (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
April 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $8.90/GJ
As at September 30, 2006, the Trust had committed to the future sale
of 255,800 barrels of crude oil at an average price of $83.29 per
barrel and 15,640,000 gigajoules (GJ) of natural gas at an average
price of $9.20 per GJ or $10.77 per mcf based on the historical
heating value of Peyto's natural gas. These contracts will generate
revenue totaling $165.2 million. Based on the market's estimate of
the future commodity prices as at September 30, 2006 the fair value
of these contracts would be $120.0 million.
Subsequent to September 30, 2006 the Trust entered into the following
contracts:
Natural Gas
Daily Price
Period Hedged Type Volume (CAD)
---------------------------------------------------------------------
Nov. 1, 2006 to Nov 30, 2006 Fixed price 5,000 GJ $5.76/GJ
Dec. 1, 2006 to Dec 31, 2006 Fixed price 5,000 GJ $7.28/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $7.25/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $7.51/GJ
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 September 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
September 30, 2006, approximately 63% 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 September 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 $3.4 million per annum.
9. Supplemental Cash Flow Information
Three Months Nine Months
Ended Ended
September 30 September 30
2006 2005 2006 2005
($000) $ $ $ $
---------------------------------------------------------------------
Cash interest paid 5,432 2,422 12,374 6,845
Cash taxes paid - 354 - 690
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
$13 million in damages for alleged breaches of duty as operator of
jointly owned properties, and an interim and permanent injunction to
prevent Peyto from proceeding with the completion of a well on those
properties. CNRL alleges that Peyto failed to take proper steps as
operator of a joint well (the "Well") on lands that offset 100% Peyto
owned lands. Peyto has filed a Statement of Defense defending the
allegations set forth in the Statement of Claim. The injunction
claimed by CNRL was to prevent Peyto from completing the Well at a
target location which had been agreed upon by both parties. Although
claimed in the Statement of Claim, CNRL did not apply for an interim
injunction, and Peyto completed the Well as planned, but no
commercial production was obtained. 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 238,371
2007 953,484
2008 1,096,641
2009 1,096,641
2010 1,096,641
2011 1,096,641
---------------------------------------------------------------------
5,578,419
---------------------------------------------------------------------
---------------------------------------------------------------------
11. Related Party Transactions
During the period ended March 31, 2006, the Trust participated in a
joint venture capital project with a company whose director was also
a Peyto director until May 16, 2006. The Trust's participation in
this joint venture amounted to $620,218. Costs associated with this
joint venture capital project 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 nine months of 2006, legal fees totaled
$439,485 (2005 - $335,243). Legal fees paid to the law firm for the
third quarter totaled $258,040 (2005 - $285,255).
12. Subsequent Events
On October 31, 2006, the Federal Government of Canada announced a
plan to begin taxing the income before distributions of flow through
vehicles such as income trusts and limited partnerships. The plan
provides for a four-year transition period for existing entities.
Given the information available at this time, the financial impact on
the Trust cannot be reasonably estimated.
Peyto Exploration & Development Corp. Information
Officers
Don Gray Glenn Booth
Chief Executive Officer Vice President, Land
Darren Gee Kathy Turgeon
President Vice President, Finance
Scott Robinson Stephen Chetner
Executive Vice President and Corporate Secretary
Chief Operating Officer
Ken Veres
Vice President, Exploration
Directors
Ian Mottershead, Chairman
Rick Braund
Don Gray
Brian Davis
John Boyd
Michael MacBean
Auditors
Deloitte & Touche 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
