SYMBOL: PEY.UN - TSX
CALGARY, May 10 /CNW/ - Peyto Energy Trust ("Peyto") is pleased to
present the operating and financial results for the first quarter of the 2006
fiscal year. Peyto has a solid foundation made up of high quality long life
natural gas assets and 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 - $1.81/boe, three months ending March 31, 2006
- Low base general and administrative costs - $0.06/boe, three months
ending March 31, 2006
- High revenue per boe - $53.57/boe, before hedging, three months
ending March 31, 2006
- High field netback - $40.02/boe, three months ending March 31, 2006
- High operatorship - we operate over 95% of our production
- Low cash distribution payout ratio - cash distributions were 44% of
funds from operations for the three months ended March 31, 2006
- Low debt to funds from operations ratio - 1.18 (net debt, before
provision for future compensation, divided by annualized first
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 $381 million issuing
units from treasury, accumulated earnings of $381 million, and
distributed $313 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
first quarter of 2006.
- Production growth - production increased 5% from 21,511 boe/d in the
first quarter of 2005 to 22,622 boe/d in the first quarter of 2006
- Production per unit - decreased 3% per trust unit from the first
quarter of 2005, after adjusting for debt and future unrealized
performance based compensation
- Per unit funds from operations growth - grew 10% from the previous
year to $0.76/unit
- Hedging - we had a $4.6 million hedging gain for the quarter versus a
hedging loss of $22.4 million in the fourth quarter of 2005, and a
hedging gain of $1.1 million in the first quarter of 2005
- Capital expenditures - $145 million was invested into finding and
developing new natural gas reserves
- Distributions per unit increased by 27% from the first quarter of
2005 while the cash payout ratio remained low at 44% compared to 45%
in the first quarter of 2005. A total of $41.5 million or $0.40 per
unit was distributed to unitholders in the first quarter of 2006.
Natural gas volumes recorded in thousand cubic feet (mcf) are converted
to barrels of oil equivalent (boe) using the ratio of six (6) thousand
cubic feet to one (1) barrel of oil (bbl).
<<
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3 Months Ended Mar. 31 %
2006 2005 Change
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Operations
Production
Natural gas (mcf/d) 110,878 103,043 8%
Oil & NGLs (bbl/d) 4,143 4,337 (4)%
Barrels of oil equivalent
(boe/d (at) 6:1) 22,622 21,511 5%
Product prices
Natural gas ($/mcf) 9.26 7.81 19%
Oil & NGLs ($/bbl) 57.12 55.52 3%
Operating expenses ($/boe) 1.81 1.22 48%
Transportation ($/boe) 0.63 0.68 (7)%
Field netback ($/boe) 40.02 35.50 13%
General & administrative expenses
($/boe) 0.06 0.06 -
Interest expense ($/boe) 1.36 0.97 40%
Financial ($000, except per unit)
Revenue 113,717 94,069 21%
Royalties (net of ARTC) 27,258 21,672 26%
Funds from operations 78,617 66,636 18%
Funds from operations per unit(x) 0.76 0.69 10%
Total distributions 41,517 30,472 36%
Total distributions per unit(x) 0.40 0.315 27%
Payout ratio 53 46 15%
Cash distributions (net of DRIP) 34,665 29,982 16%
Payout ratio 44 45 (2)%
Earnings 45,293 37,431 21%
Earnings per diluted unit(x) 0.44 0.385 14%
Capital expenditures 145,094 99,074 46%
Weighted average trust units
outstanding(x) 103,910,640 96,664,210 7%
As at March 31
Net debt (before future
compensation expense) 372,073 280,959
Unitholders' equity 449,414 217,728
Total assets 1,037,191 675,290
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(x)Note: prior periods restated for 2 for 1 split of trust units
completed May 31, 2005.
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12 Months Ended Mar. 31
2006 2005
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Net Earnings 45,293 37,431
Items not requiring cash:
Non-cash provision for (recovery of)
performance based compensation 4,822 3,927
Future income tax expense 8,677 12,469
Depletion, depreciation and accretion 19,825 12,809
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Funds from operations(1) 78,617 66,636
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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
Peyto had its most active quarter ever investing $145 million into
finding and developing new natural gas reserves. Capital expenditures
consisted of buying land, shooting seismic, drilling, completing and
connecting gas wells and constructing gas processing infrastructure. A record
$11 million was invested acquiring lands that expand our inventory of future
drilling prospects. In addition, a total of $5 million was spent on seismic
programs as part of our exploration process.
Peyto drilled and cased 40 gross (30 net) wells in the quarter while
completing 62 gross (48 net) gas zones. We spent $101 million on drilling
exploratory and development wells in the first quarter. We estimate that
increases in service costs have increased drilling related costs by 15% to 20%
from the previous year. Wellsite equipment and pipelines expenditures, which
were required to bring new wells on production, totaled $16 million for the
quarter. We were able to bring on production 49 gross (44 net) zones during
the quarter. At year end the value and reserves associated with these wells
will be moved into the proved producing category.
As part of the full cycle of developing our reserves, we also completed
construction of a new 20 mmcf/d natural gas processing plant in mid March 2006
located west of Sundance in the Wildhay area. This gas plant accounted for
$12 million of the capital expenditures for the first quarter. We now own and
operate over 175 mmcf/d of natural gas processing capacity in the Deep Basin
area.
Average production for the quarter was up 5% from Q1 2005 to 22,622 boe/d
comprised of 111 mmcf/d of gas and 4,143 bbls/d of oil and natural gas
liquids. As the Wildhay gas plant came on production late in the first
quarter, production associated with the new plant had minimal affect on the
average production for the quarter.
Gas prices after hedging averaged $9.26/mcf, which was 12% lower than the
previous quarter and 19% higher than the first quarter of 2005. Oil and
natural gas liquids price after hedging averaged $57.12/bbl for the quarter,
which was 2% lower than the previous quarter and 3% higher than a year ago.
Peyto's industry leading operating costs averaged $1.81/boe in the first
quarter down 7% from the previous quarter. In our estimation, any increase in
operating costs due to a maturing producing base will be more than offset by a
reduction in the royalty rate, resulting in a higher netback per boe. Our
design, drill and build approach continues to deliver assets with operating
costs that are roughly one quarter the sector average.
After review of the annual independent engineering evaluation of Peyto's
reserves, our banking syndicate increased our credit facilities from
$350 million to $450 million. In our opinion this is confirmation of the value
we have been able to create with our design, drill and build approach.
Activity Update
To date in 2006, Peyto has drilled 46 gross (36 net) gas wells. We have
brought on production 63 gross (54 net) zones accounting for approximately
3,300 boe/d of new production so far in 2006. At this time, we have 21 gross
(19 net) wells with over 32 net zones awaiting completion and tie-in. As with
past years, the rate we are drilling and developing our reserves far exceeds
the rate at which we are producing or depleting our assets.
We are scheduled to complete another 20 mmcf/d gas processing facility
located in the Nosehill area by August 2006. With this new gas plant, we
expect to have enough capacity to handle our current developed non producing
gas volumes. Our new Wildhay gas plant is currently producing 16 mmcf/d of
gross sales gas with our net share being approximately 2,400 boe/d. Current
production for the trust is 23,800 boe/d, which is 7% higher than the 2005
exit rate.
Historically May and June have been the wettest months in our area of
operations. During the next few months, we intend to slow the pace of our
drilling and catch up on our completion and tie-in program.
Marketing
Peyto's marketing strategy is designed to smooth out short term
fluctuations in the price of both natural gas and natural gas liquids through
future sales. It is meant to be methodical and consistent and to avoid
speculation. In general this approach will show hedging losses when short term
prices climb and hedging gains when short term prices fall. This forward price
averaging gives stability to both our monthly distributions and capital
expenditure program.
Our first quarter natural gas price, before hedging, averaged $8.63/mcf,
which was 14% higher than the previous year. Natural gas prices on the spot
daily index for the first quarter decreased by 33% from the fourth quarter of
2005. Peyto's gas price after hedging fell by 12% from the fourth quarter of
2005. Hedges for the first quarter of 2006 increased Peyto's combined gas and
liquids price by $2.28/boe. We had a hedging gain of $4.6 million for the
first quarter versus a hedging loss of $22.4 million in the fourth quarter of
2005.
As at March 31, 2006, Peyto had committed to the forward sale of 238,100
barrels of crude oil at an average price of $72.68 per barrel and 19,635,000
gigajoules (GJ) of natural gas at an average price of $8.88 per GJ. Peyto's
current forward sale volume for 2006 represents 52% of our current gas
production net of royalties and 25% of our current liquids production net of
royalties. Based on the historical heating value of Peyto's natural gas, the
price per mcf on the forward sale will be $10.39, which is 12% higher than the
price Peyto realized in the first quarter of 2006.
Outlook
Peyto's technical team continues to demonstrate the ability to design,
drill and build producing assets with lower costs and longer reserve life than
acquisitions or mergers would provide. Our drilling inventory, current hedges
and low operating costs will allow us to continue to put more assets into our
"reserve bank" than we will be distributing to unitholders. For the remainder
of 2006, it is our current intention to balance capital expenditures with the
available bank lines and cashflow after cash distributions.
If you understand the value of your own capital and are interested in
understanding the value of Peyto, we suggest you 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 first quarter results on Thursday,
May 11, 2006 at 9:00 a.m. Mountain Standard Time (MST), 11:00 a.m. Eastern
Standard Time (EST). To participate live by phone, please call 1-800-366-7449
for all 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 21188333 followed by the pound key. The replay will be
available at 11:00 a.m. MST, 1:00 p.m. EST Thursday, May 11, 2006 until
midnight EST on Thursday, May 18, 2006. The conference call can also be
accessed through the internet at
http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID(equal sign)1475320 for
the English version or
http://www.cnw.ca/fr/webcast/viewEvent.cgi?eventID(equal sign)1475320 for the
French version. The archived conference call will be available on the Peyto
website at www.peyto.com.
Annual General Meeting
The Trust's Annual General Meeting of Unitholders is scheduled for
2:30 p.m. on Tuesday, May 16, 2006 at the Sheraton Suites Calgary Eau Claire,
255 Barclay Parade Avenue SW, Calgary, Alberta.
Don T. Gray
President and Chief Executive Officer
May 10, 2006
Certain information set forth in this document and Management's
Discussion and Analysis, including management's assessment of Peyto's future
plans and operations, contains forward-looking statements. By their nature,
forward-looking statements are subject to numerous risks and uncertainties,
some of which are beyond these parties' control, including the impact of
general economic conditions, industry conditions, volatility of commodity
prices, currency fluctuations, imprecision of reserve estimates, environmental
risks, competition from other industry participants, the lack of availability
of qualified personnel or management, stock market volatility and ability to
access sufficient capital from internal and external sources. Readers are
cautioned that the assumptions used in the preparation of such information,
although considered reasonable at the time of preparation, may prove to be
imprecise and, as such, undue reliance should not be placed on forward-looking
statements. Peyto's actual results, performance or achievement could differ
materially from those expressed in, or implied by, these forward-looking
statements and, accordingly, no assurance can be given that any of the events
anticipated by the forward-looking statements will transpire or occur, or if
any of them do so, what benefits that Peyto will derive therefrom. Peyto
disclaims any intention or obligation to update or revise any forward-looking
statements, whether as a result of new information, future events or
otherwise.
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 March 31, 2006 and the audited consolidated financial
statements of Peyto Energy Trust ("Peyto") for the year ended December 31,
2005. The consolidated financial statements have been prepared in accordance
with Canadian generally accepted accounting principles ("GAAP").
The Trust was created by way of a Plan of Arrangement effective July 1,
2003 which reorganized Peyto Exploration & Development Corp. ("PEDC") from a
corporate entity into a trust. Accordingly, the consolidated financial
statements were reported on a continuity of interests basis. As such,
comparative figures for the periods prior to July 1, 2003 are the financial
results of PEDC. This discussion provides management's analysis of Peyto's
historical financial and operating results and provides estimates of Peyto's
future financial and operating performance based on information currently
available. Actual results will vary from estimates and the variances may be
significant. Readers should be aware that historical results are not
necessarily indicative of future performance. This MD&A was prepared using
information that is current as of May 9, 2006. Additional information about
Peyto, including the most recently filed annual information form is available
at www.sedar.com.
Certain information set forth in this Management's Discussion and
Analysis, including management's assessment of the Trust's future plans and
operations, contains forward-looking statements. By their nature, forward-
looking statements are subject to numerous risks and uncertainties, some of
which are beyond these parties' control, including the impact of general
economic conditions, industry conditions, volatility of commodity prices,
currency fluctuations, imprecision of reserve estimates, environmental risks,
competition from other industry participants, the lack of availability of
qualified personnel or management, stock market volatility and ability to
access sufficient capital from internal and external sources. Readers are
cautioned that the assumptions used in the preparation of such information,
although considered reasonable at the time of preparation, may prove to be
imprecise and, as such, undue reliance should not be placed on forward-looking
statements. Peyto's actual results, performance or achievement could differ
materially from those expressed in, or implied by, these forward-looking
statements and, accordingly, no assurance can be given that any of the events
anticipated by the forward-looking statements will transpire or occur, or if
any of them do so, what benefits that Peyto will derive there from. Peyto
disclaims any intention or obligation to update or revise any forward-looking
statements, whether as a result of new information, future events or
otherwise.
Management uses funds from operations to analyze the operating
performance of its energy assets. In order to facilitate comparative analysis,
funds from operations is defined throughout this report as earnings before
performance based compensation, non cash and non recurring expenses. We
believe that funds from operations is an important parameter to measure the
value of an asset when combined with reserve life. Funds from operations is
not a measure recognized by Canadian generally accepted accounting principles
("GAAP") and does not have a standardized meaning prescribed by GAAP.
Therefore, funds from operations, as defined by Peyto, may not be comparable
to similar measures presented by other issuers, and investors are cautioned
that funds from operations should not be construed as an alternative to net
earnings, cash flow from operating activities or other measures of financial
performance calculated in accordance with GAAP. Funds from operations cannot
be assured and future distributions may vary.
All references are to Canadian dollars unless otherwise indicated.
Natural gas volumes recorded in thousand cubic feet (mcf) are converted to
barrels of oil equivalent (boe) using the ratio of six (6) thousand cubic feet
to one (1) barrel of oil (bbl).
Recently, proposed new legislation to restrict foreign ownership was
issued in draft form by the Department of Finance and has prompted all trusts,
including Peyto, to review their capital structures. To the best of our
knowledge, Peyto's foreign ownership level currently stands at approximately
23.9 percent, well below the level that would jeopardize Peyto's status as a
mutual fund trust under this proposed legislation. A few trusts have
reorganized, or propose to reorganize, their units into a dual class structure
with the objective of restricting foreign ownership to less than 50 percent
and therefore retaining their status as a mutual fund trust. Peyto is an
active supporter of the efforts of the Canadian Association of Income Funds
(CAIF) which is attempting to have the Department of Finance reconsider
components of the proposed legislation. The Department of Finance has
subsequently announced that they are taking more time to consider the proposed
legislation. The Trust will continue to monitor these developments and if it
is deemed appropriate, propose an amendment to its capital structure.
OVERVIEW
Peyto is a Canadian energy trust involved in the development and
production of natural gas in Alberta's deep basin. As at December 31, 2005, we
had total proved plus probable reserves of 153.4 million barrels of oil
equivalent with a reserve life of 18.9 years as evaluated by our independent
petroleum engineers. Our production is weighted as to approximately 83%
natural gas and 17% natural gas liquids and oil.
The Peyto model is designed to deliver growth in its assets, production
and income, all on a per unit basis. The model is built around three key
principles:
- Using our technical expertise to achieve the best return on capital
employed, through the development of internally generated drilling
projects.
- A low payout ratio designed to efficiently fund our growing inventory
of drilling projects.
- Having an asset base which is made up of high quality long life
natural gas reserves.
Operating results over the last seven years indicate that we have
successfully implemented these principles. Our business model makes Peyto a
truly unique energy trust.
QUARTERLY FINANCIAL INFORMATION
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2006 2005
($000 except per
unit amounts) Q1 Q4 Q3 Q2
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Total revenue (net
of royalties) 86,459 94,111 84,912 73,473
Funds from
operations 78,617 86,607 77,179 66,548
Per unit
- basic(x) 0.76 0.85 0.78 0.69
Per unit
- diluted(x) 0.76 0.85 0.78 0.69
Earnings (loss) 45,293 60,745 37,702 25,690
Per unit
- basic(x) 0.44 0.60 0.38 0.27
Per unit
- diluted(x) 0.44 0.60 0.38 0.27
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2005 2004
($000 except per
unit amounts) Q1 Q4 Q3 Q2
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Total revenue (net
of royalties) 72,397 66,024 59,337 53,853
Funds from
operations 66,636 60,334 54,211 48,548
Per unit
- basic(x) 0.69 0.65 0.60 0.53
Per unit
- diluted(x) 0.69 0.65 0.60 0.53
Earnings (loss) 37,431 (2,558) 21,650 30,347
Per unit
- basic(x) 0.39 (0.03) 0.24 0.33
Per unit
- diluted(x) 0.39 (0.03) 0.24 0.33
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(x)Note: prior periods restated for 2 for 1 split of trust units
completed May 31, 2005.
RESULTS OF OPERATIONS
Production
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Three Months ended Mar. 31
2006 2005
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Natural gas (mmcf/d) 110.9 103.0
Oil & natural gas liquids (bbl/d) 4,143 4,337
Barrels of oil equivalent (boe/d) 22,622 21,511
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Natural gas production averaged 110.9 mmcf/d in the first quarter of
2006, 8 percent higher than the 103.0 mmcf/d reported for the same period in
2005. Oil and natural gas liquids production averaged 4,143 bbl/d, a decrease
of 4 percent from 4,337 bbl/d reported in the prior year. First quarter
production increased 5 percent from 21,511 boe/d to 22,622 boe/d. The
production increases are directly attributable to Peyto's ongoing drilling
program.
Commodity Prices
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Three Months ended Mar. 31
2006 2005
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Natural gas ($/mcf) 8.63 7.59
Hedging - gas ($/mcf) 0.63 0.22
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Natural gas - after hedging ($/mcf) 9.26 7.81
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Oil and natural gas liquids($/bbl) 61.45 57.82
Hedging - oil ($/bbl) (4.33) (2.30)
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Oil and natural gas liquids - after hedging
($/bbl) 57.12 55.52
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Total Hedging ($/boe) 2.28 0.73
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Our natural gas price before hedging averaged $8.63/mcf during the first
quarter of 2006, an increase of 14 percent from $7.59/mcf reported for the
equivalent period in 2005. Oil and natural gas liquids prices averaged
$61.45/bbl up 6 percent from $57.82/bbl a year earlier. Hedging activity for
the first quarter of 2006 accounted for $2.28/boe of Peyto's price achieved.
Expectations are for commodity prices to remain strong relative to historical
pricing.
Revenue
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Three Months ended Mar. 31
($000) 2006 2005
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Natural gas 86,162 70,421
Oil and natural gas liquids 22,911 22,567
Hedging gain (loss) 4,644 1,081
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Total revenue 113,717 94,069
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For the three months ended March 31, 2006, gross revenue increased 21
percent to $113.7 million from $94.1 million for the same period in 2005. The
increase in revenue for the period was a result of increased commodity prices
and production volumes as detailed in the following table:
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Three Months ended Mar. 31
2006 2005 Change $million
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Natural gas
Volume (mcf/d) 110,878 103,043 7,835
Volume (mmcf) 9,979 9,274 705 5.5
Price ($/mcf) 9.26 7.81 1.45 14.4
Oil & NGL
Volume (bbl/d) 4,143 4,337 (194)
Volume (mbbl) 373 390 (17) (0.9)
Price ($/bbl) 57.12 55.52 1.60 0.6
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Total revenue
($million) 113.7 94.1 19.6
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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 Mar. 31
2006 2005
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Royalties, net of ARTC ($000) 27,258 21,672
% of sales 24.1 23.2
$/boe 13.39 11.19
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For the first quarter of 2006, royalties averaged $13.39/boe or
approximately 24.1 percent of Peyto's total petroleum and natural gas sales.
The royalty rate expressed as a percentage of sales, will fluctuate from
period to period due to the fact that the Alberta Reference Price can differ
significantly from the commodity prices obtained by the Trust.
Operating Costs & Transportation
The Trust's operating expenses include all costs with respect to day-to-
day well and facility operations. Processing and gathering income related to
joint venture and third party gas reduces operating expenses.
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Three Months ended Mar. 31
2006 2005
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Operating costs ($000)
Field expenses 5,396 3,825
Processing and gathering income (1,720) (1,462)
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Total operating costs 3,676 2,363
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$/boe 1.81 1.22
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Transportation 1,274 1,316
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$/boe 0.63 0.68
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Operating costs were $3.7 million in the first quarter of 2006 compared
to $2.4 million during the same period a year earlier. As Peyto's producing
well count increased, the fixed cost structure associated with these wells
combined with a general inflationary effect of over 20% in the service sector
caused the overall cost increase. On a unit of production basis, operating
costs averaged $1.81/boe in the first quarter of 2006 compared to $1.22/boe
for the first quarter of 2005.
Netbacks
Operating netbacks represent the profit margin associated with the
production and sale of petroleum and natural gas. The primary factors that
produce Peyto's strong netbacks are a low cost structure and the high heat
content of our natural gas that results in higher commodity prices.
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Three Months ended Mar. 31
($/boe) 2006 2005
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Sale Price 55.85 48.59
Less:
Royalties 13.39 11.19
Operating costs 1.81 1.22
Transportation 0.63 0.68
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Operating netback 40.02 35.50
General and administrative 0.06 0.06
Interest on long-term debt 1.36 0.97
Capital tax - 0.05
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Cash netback 38.60 34.42
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General and Administrative Expenses
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Three Months ended Mar. 31
2006 2005
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G&A expenses ($000) 2,053 1,411
Overhead recoveries (1,927) (1,300)
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Net G&A expenses 126 111
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$/boe 0.06 0.06
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General and administrative expenses before overhead recoveries increased
to $2.1 million in the first quarter of 2006, as compared to $1.4 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 remained flat at $0.06 per boe.
Interest Expense
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Three Months ended Mar. 31
2006 2005
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Interest expense ($000) 2,767 1,871
$/boe 1.36 0.97
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First quarter 2006 interest expense was $2.8 million or $1.36/boe
compared to $1.9 million or $0.97/boe a year earlier. During 2006, average
debt levels have increased to partially fund Peyto's capital expenditures
program. Interest rates continue to be favourable and are not expected to
increase substantially in the short term. The average interest rate for the
first quarter of 2006 was 4.10% compared to 4.04% for the first quarter of
2005.
Depletion, Depreciation and Accretion
The 2006 first quarter provision for depletion, depreciation and
accretion totaled $19.8 million as compared to $12.8 million in 2005. On a
unit of production basis, depletion, depreciation and accretion costs averaged
$9.74/boe as compared to $6.62/boe in 2005. While the depletion rate has
decreased 8% from the first quarter of 2005, the increase in the provision for
depletion, depreciation and accretion costs is attributable to the increased
cost of finding and developing new reserves.
Income Taxes
The current provision for future income tax decreased to $8.7 million for
the first quarter of 2006 from $12.5 million for the same period in 2005. This
decrease is primarily due to increased capital activity generating higher tax
pools.
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 first quarter of 2006, we recorded a hedging gain of
$4.6 million as compared to a hedging gain of $1.1 million in the first
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 Price
Period Hedged Type Daily Volume (CAD)
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April 1 to June 30, 2006 Fixed price 200 bbl $64.75/bbl
April 1 to June 30, 2006 Fixed price 200 bbl $64.62/bbl
April 1 to June 30, 2006 Fixed price 200 bbl $68.64/bbl
April 1 to June 30, 2006 Fixed price 300 bbl $76.00/bbl
April 1 to June 30, 2006 Fixed price 200 bbl $81.00/bbl
July 1 to September 30, 2006 Fixed price 200 bbl $70.00/bbl
July 1 to September 30, 2006 Fixed price 200 bbl $72.15/bbl
July 1 to September 30, 2006 Fixed price 300 bbl $75.40/bbl
July 1 to September 30, 2006 Fixed price 200 bbl $80.10/bbl
October 1 to December 31, 2006 Fixed price 200 bbl $69.40/bbl
October 1 to December 31, 2006 Fixed price 200 bbl $71.10/bbl
October 1 to December 31, 2006 Fixed price 200 bbl $79.00/bbl
Natural Gas Price
Period Hedged Type Daily Volume (CAD)
-------------------------------------------------------------------------
April 1 to October 31, 2006 Fixed price 5,000 GJ $7.10/GJ
April 1 to October 31, 2006 Fixed price 5,000 GJ $7.20/GJ
April 1 to October 31, 2006 Fixed price 5,000 GJ $7.30/GJ
April 1 to October 31, 2006 Fixed price 5,000 GJ $7.35/GJ
April 1 to October 31, 2006 Fixed price 5,000 GJ $7.45/GJ
April 1 to October 31, 2006 Fixed price 5,000 GJ $7.61/GJ
April 1 to October 31, 2006 Fixed price 5,000 GJ $7.75/GJ
April 1 to October 31, 2006 Fixed price 5,000 GJ $9.30/GJ
April 1 to October 31, 2006 Fixed price 5,000 GJ $10.60/GJ
April 1 to October 31, 2006 Fixed price 5,000 GJ $10.60/GJ
April 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $9.27/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $8.71/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $9.00/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $9.05/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $10.06/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $10.28/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $11.40/GJ
Nov. 1, 2006 to March 31, 2007 Fixed price 5,000 GJ $11.60/GJ
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
Apr. 1, 2007 to October 31, 2007 Fixed price 5,000 GJ $8.60/GJ
Commodity Price Sensitivity
Our low operating costs, low distribution ratio and long reserve life
reduce our sensitivity to changes in commodity prices.
Currency Risk Management
The Trust is exposed to fluctuations in the Canadian/US dollar exchange
ratio since our natural gas and oil sales are effectively priced in US dollars
and converted to Canadian dollars. In the short term, this risk is mitigated
indirectly as a result of our commodity hedging strategy as we hedge at
Canadian prices. Over the long term, the Canadian dollar tends to rise as oil
prices rise. There is a similar correlation between oil and gas prices.
Currently we have not entered into any agreements to further manage this
specific risk.
Interest Rate Risk Management
The Trust is exposed to interest rate risk in relation to interest
expense on its revolving demand facility. Currently we have not entered into
any agreements to manage this risk. At March 31, 2006, the increase or
decrease in earnings for each 100 bps change in interest rate paid on the
outstanding revolving demand loan amounts to approximately $2.7 million per
annum.
LIQUIDITY AND CAPITAL RESOURCES
Funds from Operations
-------------------------------------------------------------------------
Three Months ended Mar. 31
($000) 2006 2005
-------------------------------------------------------------------------
Net earnings 45,293 37,431
Items not requiring cash:
Non-cash provision for performance based
compensation 4,822 3,927
Future income tax expense 8,677 12,469
Depletion, depreciation & accretion 19,825 12,809
-------------------------------------------------------------------------
Funds from operations 78,617 66,636
-------------------------------------------------------------------------
For the quarter ended March 31, 2006, funds from operations totaled
$78.6 million or $0.76 per unit, representing an 18 percent increase from the
$66.6 million, or $0.69 per unit during the same period in 2005. Peyto's
policy is to distribute approximately 50% of funds from operations to
unitholders while retaining the balance to fund its growth oriented capital
expenditures program. Our earnings and cash flow are highly sensitive to
changes in commodity prices, exchange rates and other factors that are beyond
our control. Current volatility in commodity prices creates uncertainty as to
our funds from operations and capital expenditure budget. Accordingly, we
assess results throughout the year and revise our operational plans as
necessary to reflect the most current information.
Our revenues will be impacted by drilling success and production volumes
as well as external factors such as the market prices for natural gas and
crude oil and the exchange rate of the Canadian dollar relative to the US
dollar.
Bank Debt
We have an extendible revolving term credit facility with a syndicate of
financial institutions in the amount of $350 million including a $330 million
revolving facility and a $20 million operating facility. Available borrowings
are limited by a borrowing base, which is based on the value of petroleum and
natural gas assets as determined by the lenders. The loan is reviewed annually
and may be extended at the option of the lender for an additional 364 day
period. If not extended, the revolving facility will automatically convert to
a one year and one day non revolving term loan. The loan has therefore been
classified as long term on the balance sheet. The average borrowing rate for
the first quarter of 2006 was 4.1% (2005 - 3.6%). Subsequent to March 31, the
Trust's banking syndicate has agreed to increase the credit facilities to
$450 million.
At March 31, 2006, $300 million was drawn under the facility. Working
capital liquidity is maintained by drawing from and repaying the unutilized
credit facility as needed. At March 31, 2006, we had a working capital deficit
of $84.4 million.
We believe that funds generated from our operations, together with
borrowings under our credit facility and proceeds from equity issued will be
sufficient to finance our current operations and planned capital expenditure
program. Every year since Peyto started our capital expenditures have grown.
We expect that this will again be the case in 2006. The total amount of
capital we ultimately invest in 2006 will be driven by the number and quality
of projects we generate. Capital will only be invested if it meets the long
term objectives of the trust. The majority of our capital program will involve
drilling, completion and tie in of low risk development gas wells. During the
year, Peyto will be constructing a second new gas plant to ensure that we can
efficiently access the new reserves we are finding. Peyto has the flexibility
to match planned capital expenditures to actual cash flow.
Capital
Peyto implemented a Distribution Reinvestment Plan ("DRIP") effective
with the March 2005 distribution whereby eligible unitholders may elect to
reinvest their monthly cash distributions in additional trust units at a 5%
discount to market price. On November 21, 2005 the DRIP plan was amended to
incorporate an Optional Trust Unit Purchase Plan ("OTUPP") which provides
unitholders enrolled in the DRIP with the opportunity to purchase additional
trust units from treasury using the same pricing as the DRIP.
Subsequent to March 31, 2006 451,578 trust units (113,879 pursuant to the
DRIP and 337,699 pursuant to the OTUPP) were issued for net proceeds of
$10,828,830. Subsequent to the issuance of these units, 104,481,613 trust
units were outstanding (March 31, 2006 - 104,030,035).
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 210,945 4,871,521
Trust units issued pursuant to OTUPP 91,303 2,060,662
-------------------------------------------------------------------------
Balance, March 31, 2006 104,030,035 370,046,706
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Performance Based Compensation
The Trust awards performance based compensation to employees and key
consultants annually. The performance based compensation is comprised of
market and reserve value based components.
The reserve value based component is 3% of the incremental increase in
value, if any, as adjusted to reflect changes in debt, equity and
distributions, of proved producing reserves calculated using a constant price
at December 31 of the current year and a discount rate of 8%. This methodology
can generate interim results which vary significantly from the final
compensation paid. No provision for the reserve value based component was
recorded for the first quarter of 2006.
Under the market based component, rights with a three year vesting period
are allocated to employees and key consultants. The number of rights
outstanding at any time is not to exceed 7% of the total number of trust units
outstanding. At December 31 of each year, all vested rights are automatically
cancelled and, if applicable, paid out in cash. Compensation is calculated as
the number of vested rights multiplied by the total of the market appreciation
(over the price at the date of grant) and associated distributions of a trust
unit for that period. A tax factor of 1.333 is then applied to determine the
amount to be paid.
Based on the five day weighted average trading price of the trust units
for the period ended March 31, 2006, compensation costs related to 4.5 million
non-vested rights, with an average grant price of $22.57, total $4.8 million.
The Trust records a non-cash provision for future compensation expense over
the life of the rights. The cumulative provision totals $15 million of which
$4.8 million was recorded in the three months ending March 31, 2006.
Capital Expenditures
Net capital expenditures for the first quarter of 2006 totaled
$145 million. Exploration and development related activity represented
$101 million or 70% of the total, while expenditures on facilities, gathering
systems and equipment totaled $28.2 million or 19.5% of the total. The
following table summarizes capital expenditures for the quarter.
-------------------------------------------------------------------------
Three Months ended Mar. 31
($000) 2006 2005
-------------------------------------------------------------------------
Land 10,631 2,377
Seismic 5,137 994
Drilling - Exploratory & Development 100,988 73,526
Production Equipment, Facilities & Pipelines 28,241 22,184
Acquisitions & Dispositions - -
Office Equipment 97 (7)
-------------------------------------------------------------------------
Total Capital Expenditures 145,094 99,074
-------------------------------------------------------------------------
Distributions
-------------------------------------------------------------------------
Three Months ended Mar. 31
2006 2005
-------------------------------------------------------------------------
Funds from operations ($000) 78,617 66,636
Total distributions ($000) 41,517 30,472
Total distributions per unit ($)(x) 0.40 0.315
Payout ratio (%) 53 46
Cash distributions ($000) (net of DRIP) 34,665 29,982
Payout ratio (%) 44 45
-------------------------------------------------------------------------
(x)Note: prior periods restated for 2 for 1 split of trust units
completed May 31, 2005.
Peyto's strategy is to distribute approximately 50 percent of funds from
operations to our unitholders on a monthly basis with the balance being
withheld to fund capital expenditures. As participation in the DRIP is
optional and fluctuates monthly, the payout ratio of 50 percent is based on
total distributions including those settled in units pursuant to the DRIP.
Management is prepared to adjust the payout levels to balance desired
distributions with our requirement to maintain an appropriate capital
structure. For Canadian income tax purposes distributions made are considered
a combination of income and return of capital. The portion that is return of
capital reduces the adjusted cost base of the units.
Contractual Obligations
The Trust is committed to payments under operating leases for office
space as follows:
-------------------------------------------------------------------------
$
-------------------------------------------------------------------------
2006 715,112
2007 953,484
2008 1,096,641
2009 1,096,641
2010 1,096,641
2011 1,096,641
-------------------------------------------------------------------------
6,055,160
-------------------------------------------------------------------------
-------------------------------------------------------------------------
GUARANTEES/OFF BALANCE SHEET ARRANGEMENTS
The Trust is a party to certain off balance sheet derivative financial
instruments, including fixed price contracts as discussed further in the
Hedging section.
RELATED PARTY TRANSACTIONS
During the period, the Trust paid $620,218 to a company with a
shareholder who is also a director of the Trust, related to a joint venture
capital project. Included in accounts receivable at March 31, 2006 is $659,709
owing from the company for the related cash call.
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
quarter of 2006, the accrued and actual legal fees totaled $31,747.
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 quarter of 2006, the Trust paid distributions to the
unitholders in the amount of $41.5 million (2005 - $30.5 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 14, 2006 $0.14
US Taxpayers
US unitholders who receive cash distributions are subject to a 15 percent
Canadian withholding tax, applied to the taxable portion of the distributions
as computed under Canadian tax law. US taxpayers may be eligible for a foreign
tax credit with respect to Canadian withholding taxes paid.
The taxable portion of the cash distributions, if any, is determined by
the Trust in relation to its current and accumulated earnings and profit using
US tax principles. The taxable portion so determined, is considered to be a
dividend for US tax purposes.
The non-taxable portion of the cash distributions is a return of the cost
(or other basis). The cost (or other basis) is reduced by this amount for
computing any gain or loss from disposition. However, if the full amount of
the cost (or other basis) has been recovered, any further non-taxable
distributions should be reported as a gain.
US unitholders are advised to seek legal or tax advice from their
professional advisors.
RISK MANAGEMENT
Investors who purchase our units are participating in the net funds from
operations from a portfolio of western Canadian crude oil and natural gas
producing properties. As such, the funds from operations paid to investors and
the value of the units are subject to numerous risks inherent in the oil and
natural gas industry.
Our expected funds from operations depends largely on the volume of
petroleum and natural gas production and the price received for such
production, along with the associated costs. The price we receive for our oil
depends on a number of factors, including West Texas Intermediate oil prices,
Canadian/US currency exchange rates, quality differentials and Edmonton par
oil prices. The price we receive for our natural gas production is primarily
dependent on current Alberta market prices. Peyto's marketing strategy is
designed to smooth out short term fluctuations in the price of both natural
gas and natural gas liquids through future sales. It is meant to be methodical
and consistent and to avoid speculation.
Although our focus is on internally generated drilling programs, any
acquisition of oil and natural gas assets depends on our assessment of value
at the time of acquisition. Incorrect assessments of value can adversely
affect distributions to unitholders and the value of the units. We employ
experienced staff on our team and perform appropriate levels of due diligence
on our analysis of acquisition targets, including a detailed examination of
reserve reports; if appropriate, re-engineering of reserves for a large
portion of the properties to ensure the results are consistent; site
examinations of facilities for environmental liabilities; detailed examination
of balance sheet accounts; review of contracts; review of prior year tax
returns and modeling of the acquisition to attempt to ensure accretive results
to the unitholders.
Inherent in development of the existing oil and gas reserves are the
risks, among others, of drilling dry holes, encountering production or
drilling difficulties or experiencing high decline rates in producing wells.
To minimize these risks, we employ experienced staff to evaluate and operate
wells and utilize appropriate technology in our operations. In addition, we
use prudent work practices and procedures, safety programs and risk management
principles, including insurance coverage against certain potential losses.
The value of our Trust units is based on among other things, the
underlying value of the oil and natural gas reserves. Geological and
operational risks can affect the quantity and quality of reserves and the cost
of ultimately recovering those reserves. Lower oil and gas prices increase the
risk of write downs on our oil and gas property investments. In order to
mitigate this risk, our proven and probable oil and gas reserves are evaluated
each year by a firm of independent reservoir engineers. The reserves committee
of the Board of Directors reviews and approves the reserve report.
Our access to markets may be restricted at times by pipeline or
processing capacity. We minimize these risks by controlling as much of our
processing and transportation activities as possible and ensuring
transportation and processing contracts are in place with reliable cost
efficient counter parties.
The petroleum and natural gas industry is subject to extensive controls,
regulatory policies and income and resource taxes imposed by various levels of
government. These regulations, controls and taxation policies are amended from
time to time. We have no control over the level of government intervention or
taxation in the petroleum and natural gas industry. However, we operate in
such a manner to ensure, to the best of our knowledge that we are in
compliance with all applicable regulations and are able to respond to changes
as they occur.
The petroleum and natural gas industry is subject to both environmental
regulations and an increased environmental awareness. We have reviewed our
environmental risks and are, to the best of our knowledge, in compliance with
the appropriate environmental legislation and have determined that there is no
current material impact on our operations.
We are subject to financial market risk. In order to maintain substantial
rates of growth, we must continue reinvesting in, drilling for or acquiring
petroleum and natural gas. Our capital expenditure program is funded primarily
through funds from operations, debt and equity.
DISCLOSURE CONTROLS AND PROCEDURES
Disclosure controls and procedures are designed to provide reasonable
assurance that all relevant information is gathered and reported to senior
management, including the Chief Executive Officer ("CEO") and Vice President,
Finance ("VPF"), on a timely basis so that appropriate decisions can be made
regarding public disclosure.
As of the end of the period covered by this report, Peyto's management
evaluated the effectiveness of the design and operation of its disclosure
controls and procedures, under the supervision of, and with the participation
of the CEO and VPF. Based on this evaluation, the CEO and VPF have concluded
that Peyto's disclosure controls and procedures, as defined in Multilateral
Instrument 52-109, Certification of Disclosure in Issuers Annual and Interim
Filings are effective to ensure that material information relating to Peyto is
made known to management on a timely basis and is included in this report.
CRITICAL ACCOUNTING ESTIMATES
Reserve Estimates
Estimates of oil and natural gas reserves, by necessity, are projections
based on geologic and engineering data, and there are uncertainties inherent
to the interpretation of such data as well as the projection of future rates
of production and the timing of development expenditures. Reserve engineering
is an analytical process of estimating underground accumulations of oil and
natural gas that can be difficult to measure. The accuracy of any reserve
estimate is a function of the quality of available data, engineering and
geological interpretation and judgment. Estimates of economically recoverable
oil and natural gas reserves and future net cash flows necessarily depend upon
a number of variable factors and assumptions, such as historical production
from the area compared with production from other producing areas, the assumed
effects of regulations by governmental agencies and assumptions governing
future oil and natural gas prices, future royalties and operating costs,
development costs and workover and remedial costs, all of which may in fact
vary considerably from actual results. For these reasons, estimates of the
economically recoverable quantities of oil and natural gas attributable to any
particular group of properties, classifications of such reserves based on risk
recovery, and estimates of the future net cash flows expected there from may
vary substantially. Any significant variance in the assumptions could
materially affect the estimated quantity and value of the reserves, which
could affect the carrying value of the Trust's oil and natural gas properties
and the rate of depletion of the oil and natural gas properties as well as the
calculation of the reserve value based compensation. Actual production,
revenues and expenditures with respect to the Trust's reserves will likely
vary from estimates, and such variances may be material.
The Trust's estimated quantities of proved and probable reserves at
December 31, 2005 were audited by independent petroleum engineers Paddock
Lindstrom & Associates Ltd. Paddock has been evaluating reserves in this area
and for Peyto for 7 consecutive years.
Depletion and Depreciation Estimate
We follow the full cost method of accounting for petroleum and natural
gas operations whereby all costs of exploring for and developing petroleum and
natural gas reserves are capitalized. Such costs include land acquisition
costs, geological and geophysical costs, carrying charges on non-producing
properties, costs of drilling both productive and non-productive wells and
overhead charges directly related to acquisition, exploration and development
activities.
All costs of exploring for and developing petroleum and natural gas
reserves, together with the costs of production equipment, are depleted and
depreciated on the unit of production method based on estimated gross proven
reserves. Petroleum and natural gas reserves and production are converted into
equivalent units based upon estimated relative energy content (6 mcf to 1
barrel of oil).
Costs of acquiring unproved properties are initially excluded from
depletion calculations. These unevaluated properties are assessed periodically
to ascertain whether impairment has occurred. When proven reserves are
assigned or the property is considered to be impaired, the cost of the
property or the amount of the impairment is added to costs subject to
depletion calculations.
Full Cost Accounting Ceiling Test
The carrying value of property, plant and equipment is reviewed at least
annually for impairment. Impairment occurs when the carrying value of the
assets is not recoverable by the future undiscounted cash flows. The ceiling
test is based on estimates of proved reserves, production rates, estimated
future petroleum and natural gas prices and costs and other relevant
assumptions. By their nature, these estimates are subject to measurement
uncertainty and the impact on the financial statements could be material. Any
impairment would be charged as additional depletion and depreciation expense.
Asset Retirement Obligation
The asset retirement obligation is estimated based on existing laws,
contracts or other policies. The fair value of the obligation is based on
estimated future costs for abandonment and reclamation discounted at a credit
adjusted risk free rate. The liability is adjusted each reporting period to
reflect the passage of time and for revisions to the estimated future cash
flows, with the accretion charged to earnings. By their nature, these
estimates are subject to measurement uncertainty and the impact on the
financial statements could be material.
Future Market Performance Based Compensation
The provision for future market based compensation is estimated based on
current market conditions, distribution history and on the assumption that all
outstanding rights will be paid out according to the vesting schedule. The
conditions at the time of vesting could vary significantly from the current
conditions and may have a material effect on the calculation.
Reserve Value Performance Based Compensation
The reserve value based compensation is calculated using the 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 2005
Q1 Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Operations
Production
Natural gas
(mcf/d) 110,878 108,356 108,460 106,866 103,043
Oil & NGLs
(bbl/d) 4,143 4,185 4,569 4,653 4,337
Barrels of
oil equivalent
(boe/d (at)
6:1) 22,622 22,245 22,646 22,464 21,511
Average product
prices
Natural gas
($/mcf) 9.26 10.55 8.67 8.00 7.81
Oil & natural
gas liquids
($/bbl) 57.12 58.43 57.22 51.03 55.52
Average
operating
expenses
($/boe) 1.81 1.95 1.70 1.30 1.22
Average
transportation
costs ($/boe) 0.63 0.70 0.66 0.68 0.68
Field netback
($/boe) 40.02 43.33 38.39 33.97 35.50
General &
administrative
expense ($/boe) 0.06 0.05 0.13 0.10 0.06
Interest
expense
($/boe) 1.36 0.91 1.16 1.25 0.97
Financial
($000 except
per unit)
Revenue 113,717 127,633 110,566 99,427 94,069
Royalties
(net of ARTC) 27,258 33,522 25,654 25,954 21,672
Funds from
operations 78,617 86,607 77,179 66,548 66,636
Funds from
operations
per unit(x) 0.76 0.85 0.78 0.69 0.69
Total
distributions 41,517 36,773 35,505 33,898 30,472
Total
distributions
per unit(x) 0.40 0.36 0.36 0.35 0.315
Payout ratio 53% 42% 46% 51% 46%
Cash
distributions
(net of DRIP) 34,665 33,771 32,318 31,023 29,982
Payout ratio 44% 39% 42% 47% 45%
Earnings 45,293 60,745 37,702 25,690 37,431
Earnings
per diluted
unit(x) 0.44 0.60 0.38 0.27 0.39
Capital
expenditures 145,094 107,647 93,001 58,730 99,074
Weighted
average
trust
units out-
standing(x) 103,910,640 102,148,411 98,584,597 96,848,988 96,664,210
(x) Note: prior periods restated for 2 for 1 split of trust units
completed May 31, 2005.
Peyto Energy Trust
Consolidated Balance Sheets
(unaudited)
March 31, December 31,
2006 2005
$
-------------------------------------------------------------------------
Assets
Current
Accounts receivable (Note 4) 76,549,171 82,793,463
Due from private placements - 27,450,247
Prepaid expenses and deposits 2,100,918 1,795,540
-------------------------------------------------------------------------
78,650,089 112,039,250
Property, plant and equipment (Note 2) 958,541,280 832,887,287
-------------------------------------------------------------------------
1,037,191,369 944,926,537
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities and Unitholders' Equity
Current
Accounts payable and accrued liabilities 138,779,125 208,284,019
Capital taxes payable 110,412 110,412
Cash distributions payable 11,833,395 11,529,973
Provision for future performance based
compensation 12,286,051 8,748,198
-------------------------------------------------------------------------
163,008,983 228,672,602
-------------------------------------------------------------------------
Long-term debt (Note 3) 300,000,000 180,000,000
Provision for future performance based
compensation 2,685,313 1,400,970
Asset retirement obligations 5,113,203 4,729,098
Future income taxes 116,969,965 108,292,966
-------------------------------------------------------------------------
424,768,481 294,423,034
-------------------------------------------------------------------------
Unitholders' equity
Unitholders' capital (Note 4) 370,046,706 328,735,910
Units to be issued (Note 4) 10,828,830 28,332,345
Accumulated earnings 381,219,006 335,925,837
Accumulated distributions (Note 5) (312,680,637) (271,163,191)
-------------------------------------------------------------------------
449,413,905 421,830,901
-------------------------------------------------------------------------
1,037,191,369 944,926,537
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
On behalf of the Board:
(signed) "Michael MacBean" (signed) "Donald T. Gray"
Director Director
Peyto Energy Trust
Consolidated Statements of Earnings and Accumulated Earnings
(unaudited)
For the three months ended March 31,
2006 2005
$ $
-------------------------------------------------------------------------
Revenue
Petroleum and natural gas sales, net 86,459,216 72,396,948
-------------------------------------------------------------------------
Expenses
Operating (Note 6) 3,675,966 2,363,373
Transportation 1,273,833 1,316,167
General and administrative (Note 7) 125,933 110,643
Future performance based compensation
provision 4,822,196 3,927,039
Interest on long term debt 2,766,580 1,870,657
Depletion, depreciation and accretion (Note 2) 19,824,539 12,809,296
-------------------------------------------------------------------------
32,489,047 22,397,175
-------------------------------------------------------------------------
Earnings before taxes 53,970,169 49,999,773
-------------------------------------------------------------------------
Taxes
Future income tax expense 8,677,000 12,469,000
Capital tax expense - 100,000
-------------------------------------------------------------------------
8,677,000 12,569,000
-------------------------------------------------------------------------
Net earnings for the period 45,293,169 37,430,773
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Accumulated earnings, beginning of period 335,925,837 174,358,093
-------------------------------------------------------------------------
Accumulated earnings, end of period 381,219,006 211,788,866
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per unit (Note 4)
Basic 0.44 0.385
Diluted 0.44 0.385
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
Peyto Energy Trust
Consolidated Statements of Cash Flows
(unaudited)
For the three months ended March 31,
2006 2005
$ $
-------------------------------------------------------------------------
Cash provided by (used in)
Operating Activities
Net earnings for the period 45,293,169 37,430,773
Items not requiring cash:
Future income tax expense 8,677,000 12,469,000
Depletion, depreciation and accretion 19,824,539 12,809,296
Change in non-cash working capital related to
operating activities 25,266,416 (9,700,436)
-------------------------------------------------------------------------
99,061,124 53,008,633
-------------------------------------------------------------------------
Financing Activities
Issue of trust units, net of costs and DRIP 16,955,049 4,430,515
Cash distribution paid (net of DRIP) (34,665,214) (29,982,211)
Increase in bank debt 120,000,000 30,000,000
Change in non-cash working capital related
to financing activities 19,655,649 28,169,020
-------------------------------------------------------------------------
121,945,484 32,617,324
-------------------------------------------------------------------------
Investing Activities
Additions to property, plant and equipment (145,094,428) (99,074,410)
Change in non-cash working capital related
to investing activities (75,912,180) 13,448,453
-------------------------------------------------------------------------
(221,006,608) (85,625,957)
-------------------------------------------------------------------------
Net increase (decrease) in cash - -
Cash, beginning of period - -
-------------------------------------------------------------------------
Cash, end of period - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
Peyto Energy Trust
Notes to Consolidated Financial Statements
(unaudited)
March 31, 2006 and 2005
1. Summary of Significant Accounting Policies
The unaudited interim consolidated financial statements of Peyto
Energy Trust (the "Trust") follow the same accounting policies as the
most recent annual audited financial statements. The interim
consolidated financial statement note disclosures do not include all
of those required by Canadian generally accepted accounting
principles applicable for annual financial statements. Accordingly,
these interim financial statements should be read in conjunction with
the 2005 audited consolidated financial statements.
These financial statements include the accounts of Peyto Energy Trust
and its wholly owned subsidiaries, Peyto Exploration & Development
Corp. and Peyto Operating Trust.
Certain comparative figures have been reclassified to ensure
consistency with current period presentation.
2. Property, Plant and Equipment
March 31, December 31,
2006 2005
$ $
---------------------------------------------------------------------
Property, plant and equipment 1,121,398,873 976,005,103
Accumulated depletion and depreciation (162,857,593) (143,117,816)
---------------------------------------------------------------------
958,541,280 832,887,287
---------------------------------------------------------------------
---------------------------------------------------------------------
At March 31, 2006 costs of $39,073,898 (March 31, 2005 - $28,663,020)
related to undeveloped land have been excluded from the depletion and
depreciation calculation.
3. Long-Term Debt
The Trust has a syndicated $350 million extendible revolving credit
facility. The facility is made up of a $20 million working capital
sub-tranche and a $330 million production line. The facilities are
available on a revolving basis for a period of at least 364 days and
upon the term out date may be extended for a further 364 day period
at the request of the Trust, subject to approval by the lenders. In
the event that the revolving period is not extended, the facility is
available on a non-revolving basis for a one year term, at the end of
which time the facility would be due and payable. Outstanding amounts
on this facility bear interest at rates determined by the Trust's
debt to cash flow ratio that range from prime to prime plus 0.75% for
debt to cash flow ratios ranging from less than 1:1 to greater than
2.5:1. A General Security Agreement with a floating charge on land
registered in Alberta is held as collateral by the bank. Subsequent
to March 31, the Trust's banking syndicate has agreed to increase the
credit facilities to $450 million.
4. Unitholders' Capital
Authorized: Unlimited number of voting trust units
Issued and Outstanding
Number of Amount
Trust Units (no par value) Shares/Units $
---------------------------------------------------------------------
Balance, December 31, 2004 47,725,272 138,953,026
Trust units issued by private placement 670,000 31,586,375
Trust unit issue costs - (103,010)
Trust units issued pursuant to DRIP 28,645 1,356,148
Trust units issued pursuant to 2 for 1
split 48,423,917 -
Trust units issued by public offering 5,000,000 152,750,000
Trust unit issue costs - (8,054,775)
Trust units issued pursuant to DRIP 279,561 7,448,146
Trust units issued pursuant to OTUPP 206,452 4,800,000
Balance, December 31, 2005 102,333,847 328,735,910
Trust units issued by private placement 1,393,940 34,378,613
Trust units issued pursuant to DRIP 210,945 4,871,521
Trust units issued pursuant to OTUPP 91,303 2,060,662
---------------------------------------------------------------------
Balance, March 31, 2006 104,030,035 370,046,706
---------------------------------------------------------------------
---------------------------------------------------------------------
Units to be Issued
On March 2, 2005, Peyto implemented a Distribution Reinvestment Plan
("DRIP"). On November 21, 2005 the DRIP plan was amended to
incorporate an Optional Trust Unit Purchase Plan ("OTUPP") which
provides unitholders enrolled in the DRIP with the opportunity to
purchase additional trust units from treasury subject to certain
limitations, using the same pricing as the DRIP. On April 13, 2006,
at a price of $23.98 per trust unit, 113,879 trust units were issued
from treasury pursuant to the DRIP, and 337,699 trust units were
issued from treasury pursuant to the OTUPP. $8,098,020 was included
in accounts receivable for the funds due Peyto under the OTUPP.
Per Unit Amounts
Earnings per unit have been calculated based upon the weighted
average number of units outstanding during the period of 103,910,640
(2005 - 96,664,210). There are no dilutive instruments outstanding.
(x)Note: prior periods have been restated for 2 for 1 split of trust
units completed May 31, 2005.
5. Accumulated Distributions
Peyto's strategy is to distribute approximately 50 percent of funds
from operations to our unitholders on a monthly basis with the
balance being withheld to fund capital expenditures. Management and
the Board are prepared to adjust the payout levels to balance desired
distributions with our requirement to maintain an appropriate capital
structure. During the quarter, the Trust paid total distributions to
the unitholders in the aggregate amount of $41.5 million of which
$34.7 million was settled in cash and $6.8 million was settled by the
issuance of trust units pursuant to the DRIP (2005 - total
$30.5 million; cash $30 million and DRIP $0.5 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 14, 2006 $0.14
6. Operating Expenses
The Trust's operating expenses include all costs with respect to
day-to-day well and facility operations. Processing and gathering
income related to joint venture and third party natural gas reduces
operating expenses.
2006 2005
$ $
---------------------------------------------------------------------
Field expenses 5,395,979 3,825,767
Processing and gathering income (1,720,013) (1,462,394)
---------------------------------------------------------------------
Total operating costs 3,675,966 2,363,373
---------------------------------------------------------------------
---------------------------------------------------------------------
7. General and Administrative Expenses
General and administrative expenses are reduced by operating and
capital overhead recoveries from operated properties.
2006 2005
$ $
---------------------------------------------------------------------
G&A expenses 2,052,681 1,410,620
Overhead recoveries (1,926,748) (1,299,977)
Net G&A expenses 125,933 110,643
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
March 31, 2006 is as follows:
Weighted
Crude Oil Average
Period Hedged Type Daily Volume Price (CAD)
---------------------------------------------------------------------
April 1 to June 30, 2006 Fixed price 1,100 bbl $71.46/bbl
July 1 to September 30,
2006 Fixed price 900 bbl $74.52/bbl
October 1 to December 31,
2006 Fixed price 600 bbl $73.17/bbl
Weighted
Natural Gas Average
Period Hedged Type Daily Volume Price (CAD)
---------------------------------------------------------------------
April 1 to October 31, 2006 Fixed price 50,000 GJ $8.23/GJ
April 1 to March 31, 2007 Fixed price 5,000 GJ $9.27/GJ
Nov. 1, 2006 to March 31,
2007 Fixed price 45,000 GJ $10.00/GJ
April 1 to October 31, 2007 Fixed price 5,000 GJ $8.60/GJ
As at March 31, 2006, the Trust had committed to the future sale of
238,100 barrels of crude oil at an average price of $72.68 per barrel
and 19,635,000 gigajoules (GJ) of natural gas at an average price of
$8.88 per GJ or $10.39 per mcf based on the historical heating value
of Peyto's natural gas. These contracts will generate revenue
totaling $191.7 million. Based on the market's estimate of the future
commodity prices as at March 31, 2006 the fair value of these
contracts would be $171.6 million.
Subsequent to March 31, 2006 the Trust entered into the following
contracts:
Natural Gas
Period Hedged Type Daily Volume Price (CAD)
---------------------------------------------------------------------
April 1 to October 31, 2007 Fixed price 5,000 GJ $10.25/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 March 31, 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 March 31,
2006, approximately 39% 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 March 31, 2006, the
increase or decrease in earnings for each 1% change in interest rate
paid on the outstanding revolving demand loan amounts to
approximately $2.7 million per annum.
9. Supplemental Cash Flow Information
2006 2005
$ $
---------------------------------------------------------------------
Cash interest paid during the period 2,766,580 1,870,657
Cash taxes paid during the period - -
---------------------------------------------------------------------
---------------------------------------------------------------------
10. Contingencies and Commitments
a) Contingent Liability
From time to time, Peyto is the subject of litigation arising out of
Peyto's operations. Damages claimed pursuant to such litigation,
including the litigation discussed below, may be material or may be
indeterminate and the outcome of such litigation may materially
impact Peyto's financial condition or results of operations. While
Peyto assesses the merits of each lawsuit and defends itself
accordingly, Peyto may be required to incur significant expenses or
devote significant resources to defending itself against such
litigation. These claims are not currently expected to have a
material impact on Peyto's financial position.
Peyto has been named in a Statement of Claim issued by Canadian
Natural Resources Limited and affiliates ("CNRL"), claiming $13M in
damages for alleged breaches of duty as operator of jointly owned
properties, and an interim and permanent injunction to prevent Peyto
from proceeding with the completion of a well on those properties.
CNRL alleges that Peyto failed to take proper steps as operator of a
joint well (the "Well") on lands that offset 100% Peyto owned lands.
Peyto has filed a Statement of Defence defending the allegations set
forth in the Statement of Claim. The injunction claimed by CNRL was
to prevent Peyto from completing the Well at a target location which
had been agreed upon by both parties. Although claimed in the
Statement of Claim, CNRL did not apply for an interim injunction, and
Peyto completed the Well as planned, but no commercial production was
obtained. Accordingly, it remains to be seen whether CNRL will
proceed with the action. If the action goes ahead, Peyto intends to
defend itself vigorously. Although the outcome of this matter is not
determinable at this time, Peyto believes that this claim will not
have a material adverse effect on Peyto's financial position or
results of operations.
b) Commitments
The Trust is committed to payments under operating leases for office
space as follows:
$
---------------------------------------------------------------------
2006 715,112
2007 953,484
2008 1,096,641
2009 1,096,641
2010 1,096,641
2011 1,096,641
---------------------------------------------------------------------
6,055,160
---------------------------------------------------------------------
---------------------------------------------------------------------
11. Related Party Transactions
During the period, the Trust paid $620,218 to a company with a
shareholder who is also a director of the Trust, related to a joint
venture capital project. Costs associated with this joint venture
capital project are billed and paid in accordance with normal
business operations. Included in accounts receivable at March 31,
2006 is $659,709 owing from the company for the related cash call.
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 quarter of 2006, the accrued and actual
legal fees totaled $31,747 (2005 - $80,000).
Peyto Exploration & Development Corp. Information
Officers
Don Gray Glenn Booth
President and Chief Executive Officer Vice President, Land
Ken Veres Kathy Turgeon
Vice-President, Exploration Vice President, Finance
Darren Gee Stephen Chetner
Vice President, Engineering Corporate Secretary
Scott Robinson Cheree Stephenson
Vice President, Operations Controller
Directors
Ian Mottershead
Rick Braund
Don Gray
Brian Craig
Roberto Bosdachin
John Boyd
Michael MacBean
Auditors
Deloitte & Touche LLP
Solicitors
Burnet, Duckworth & Palmer LLP
Bankers
Bank of Montreal
Union Bank of California
Canadian Imperial Bank of Commerce
Royal Bank of Canada
BNP Paribas
Transfer Agent
Valiant Trust Company
Head Office
2900, 450 - 1st Street SW
Calgary, AB
T2P 5H1
Phone: 403.261.6081
Fax: 403.451.4100
Web: www.peyto.com
Stock Listing Symbol: PEY.un
Toronto Stock Exchange
>>
%SEDAR: 00019597E
