SYMBOL: PEY.UN - TSX
CALGARY, Aug. 10 /CNW/ - Peyto Energy Trust ("Peyto") is a leader in the
exploration and development of natural gas in western Canada. Our core areas
are located in Alberta's premier gas exploration area, the Deep Basin. The
combination of our solid foundation and our ability to profitably find and
develop oil and natural gas reserves makes Peyto a unique energy trust. We are
proud to present our operating and financial results for the second quarter of
the 2005 fiscal year.
The following summarizes the Trust's foundation.
- Long reserve life Proved 12.2 years, Proved Plus Probable 17.2 years
at the beginning of 2005
- Low operating costs $1.30/boe, second quarter 2005
- Low base general and administrative costs $0.10/boe, second quarter
2005
- High netback - $32.56/boe, second quarter 2005
- High operatorship - 97% of production
- Low cash distribution payout ratio 51% of second quarter 2005 funds
from operations
- Low debt to funds from operations ratio - 1.14 (net debt, before
provision for future compensation, divided by annualized second
quarter 2005 funds from operations)
- Since inception, Peyto has raised a total of $173.8 million issuing
units from treasury, accumulated earnings of $237.5 million, and
distributed $198.9 million to unitholders
- Transparent capital structure - no convertible debentures, no
exchangeable shares, no stock options, no warrants
In spite of an unusually wet spring in our area of operations, production
grew 4% from the first quarter of the year. This represents our 22nd
consecutive period of quarterly production growth from 110 boe/d in the fourth
quarter of 1999 to 22,464 boe/d in this quarter. What makes this achievement
unique is how profitably we have been able to find and develop such high
quality reserves relying solely on the expertise of our technical team. The
following summarizes performance highlights for the second quarter of 2005.
- Production growth - production increased 21% from 18,544 boe/d in 2004
to 22,464 boe/d in the second quarter of 2005
- Per unit production growth - increased 19% per trust unit after
adjusting for debt and bonuses
- Per unit funds from operations growth - increased 30% in the second
quarter of 2005 compared to the second quarter of 2004
- Capital expenditures - $59 million was spent to find and develop new
natural gas reserves
- Cash distributions per unit increased by 37% from the second quarter
of 2004 while the payout ratio remained a low 51%. A total of
$34 million or $0.35 per unit was distributed to unitholders in the
second quarter of 2005.
- Trust units split 2 for 1 on May 31, 2005.
Natural gas volumes recorded in thousand cubic feet (mcf) are converted
to barrels of oil equivalent (boe) using the ratio of six (6) thousand cubic
feet to one (1) barrel of oil (bbl).
<<
-------------------------------------------------------------------------
3 Months Ended June 30 % 6 Months Ended June 30 %
2005 2004 Change 2005 2004 Change
-------------------------------------------------------------------------
Operations
Production
Natural gas
(mcf/d) 106,866 87,753 22% 104,965 82,743 27%
Oil & NGLs
(bbl/d) 4,653 3,918 19% 4,495 3,598 25%
Barrels of
oil
equivalent
(boe/d (at)
6:1) 22,464 18,544 21% 21,990 17,389 26%
Product prices
Natural gas
($/mcf) 8.00 7.32 9% 7.91 7.46 6%
Oil & NGLs
($/bbl) 51.03 40.06 27% 53.18 39.85 33%
Operating
expenses
($/boe) 1.30 1.04 25% 1.26 1.06 19%
Transportation
($/boe) 0.68 0.74 -8% 0.68 0.66 3%
Field netback
($/boe) 33.97 30.14 13% 34.71 31.16 11%
General &
administrative
expenses ($/boe) 0.10 0.30 -67% 0.08 0.23 -65%
Interest expense
($/boe) 1.25 0.99 26% 1.11 0.98 13%
Financial ($000,
except per unit)
Revenue 99,427 72,757 37% 193,496 138,508 40%
Royalties (net
of ARTC) 25,954 18,904 37% 47,626 34,457 38%
Funds from
operations 66,548 48,548 37% 133,184 94,560 41%
Funds from
operations per
unit(x) 0.69 0.53 30% 1.38 1.04 33%
Cash
distributions 33,898 23,320 45% 64,370 43,896 47%
Cash
distributions per
unit(x) 0.35 0.255 37% 0.665 0.48 39%
Percentage of
funds from
operations
distributed 51 48 6% 48 46 4%
Earnings 25,690 30,347 -15% 63,121 54,690 15%
Earnings per
diluted unit(x) 0.27 0.33 -18% 0.65 0.60 8%
Capital
expenditures 58,730 37,067 58% 157,805 98,255 61%
Weighted average
trust units
outstand-
ing(x) 96,848,988 91,450,544 6% 96,757,110 91,446,916 6%
As at June 30
Net debt (before
future
compensation
expense) 304,165 210,057 45%
Unitholders'
equity 212,395 128,755 65%
Total assets 726,064 472,528 54%
-------------------------------------------------------------------------
(x)Note: prior periods restated for 2 for 1 split of trust units
completed May 31, 2005.
Funds from operations
Management uses funds from operations to analyze the operating
performance of its energy assets. In order to facilitate comparative analysis,
funds from operations is defined throughout this report as earnings before
bonuses, non cash and non recurring expenses. We believe that funds from
operations is an important parameter to measure the value of an asset when
combined with reserve life. Funds from operations is not a measure recognized
by Canadian generally accepted accounting principles ("GAAP") and does not
have a standardized meaning prescribed by GAAP. Therefore, funds from
operations, as defined by Peyto, may not be comparable to similar measures
presented by other issuers, and investors are cautioned that funds from
operations should not be construed as an alternative to net earnings, cash
flow from operating activities or other measures of financial performance
calculated in accordance with GAAP. Funds from operations cannot be assured
and future distributions may vary.
-------------------------------------------------------------------------
3 Months Ended 6 Months Ended
June 30 June 30
2005 2004 2005 2004
-------------------------------------------------------------------------
Earnings 25,690 30,347 63,121 54,690
Items not requiring cash:
Provision for bonuses 21,118 3,087 25,045 11,611
Future income tax expense 5,261 4,812 17,730 9,929
Depletion, depreciation and
accretion 14,479 10,302 27,288 18,330
-------------------------------------------------------------------------
Funds from operations 66,548 48,548 133,184 94,560
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Quarterly Review
In the second quarter, we invested $58.7 million, into finding and
developing new gas reserves in our core areas. Costs associated with drilling
and completing new reserves accounted for $46.4 million of the total, while
pipeline and facility construction accounted for $7.9 million. Completion and
tie-in activity was curtailed by an unusually long period of wet conditions
while our drilling activity was focused on more accessible areas. Peyto
drilled 20 gross (16.4 net) wells in the second quarter 2005 and brought
19.9 net zones on production.
Operating costs averaged $1.30 per boe. Our cost structure continues to
be one of the lowest and most stable in the North American energy sector. Over
the past five years we have managed to keep our operating costs flat while we
have increased our production 12 fold. Commodity prices were very strong
during the quarter averaging $8.00 per mcf of natural gas and $51.03 per
barrel of oil and natural gas liquids. The liquids price was lower than the
previous quarter due to higher trucking costs associated with the unusually
wet weather and a reduction in the premium for condensate realized in the
first quarter.
Activity Update
To date in 2005, Peyto has drilled 68 gross (57.5 net) wells making this
the most active drilling year in our six year history. We currently have 8
rigs active in core areas and anticipate that this level of activity will
continue throughout the balance of the year. After a period of curtailed
tie-in activity, our current production has stabilized at 22,500 boe/d.
Surface conditions have now improved and will allow us to access more than 65
net zones that have been drilled and are awaiting tie-in. By year end, Peyto's
2005 capital program will have proven up approximately 150 net zones, with the
majority of them on production. In some new areas where we own no
infrastructure, limits on surface access and third party processing capacity
has resulted in delays bringing wells on production. The majority of these
delays are expected to be resolved by year end.
Peyto has committed to the forward sale of 543,900 barrels of crude oil
at an average price of $61.51 per barrel and 29,690,000 gigajoules (GJ) of
natural gas at an average price of $7.65 per GJ. This hedged volume represents
5% of the total proven reserves that were assigned at the beginning of the
year. Based on the historical heating value of Peyto's natural gas, the price
per mcf on the forward sale will be $8.95, 12% higher than the price realized
in the second quarter of 2005.
Outlook
Our technical team has successfully expanded the quantity of our
internally generated investments without compromising the quality. Capital
expenditures for 2005 continue to be on a record pace and are forecast to be
between $260 million and $300 million. As with previous years, the majority of
our capital program will involve drilling, completion and tie in of lower risk
development gas wells adjacent to existing infrastructure in Peyto's core
areas. These expenditures will be funded with a combination of funds from
operations, working capital, equity and bank lines.
Our performance combined with the foundation we have built clearly
indicates that our business strategy works. If you are interested in learning
more about our business and willing to invest some of your time to understand
Peyto's past and future, we suggest that you visit the Peyto website at
www.peyto.com where you will find a current presentation, financial and
historical news releases and an updated insider trading summary.
Conference Call and Webcast
A conference call will be held with the senior management of Peyto to
answer questions with respect to the 2005 second quarter results on Thursday,
August 11, 2005 at 11:00 a.m. Mountain Standard Time (MST), 1:00 p.m. Eastern
Standard Time (EST). To participate, please call 1-416-640-4127 (Toronto area)
or 1-866-250-4892 for all other participants. The conference call will also be
available on replay by calling 1-416-640-1917 (Toronto area) or 1-877-289-8525
for all other parties, using passcode 21133053 followed by the pound key. The
replay will be available at 1:00 p.m. MST, 3:00 p.m. EST Thursday, August 11,
2005 until midnight EST on Thursday, August 18, 2005. The conference call can
also be accessed through the internet at
http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID(equal sign)1198780 for
the English version or
http://www.cnw.ca/fr/webcast/viewEvent.cgi?eventID(equal sign)1198780 for the
French version. The webcast will be archived by 3:00 p.m. EST on August 11,
2005 and will be available for 30 days at this same link.
Don T. Gray
President and Chief Executive Officer
August 10, 2005
Certain information set forth in this document and Management's
Discussion and Analysis, including management's assessment of the Trust's
future plans and operations, contains forward-looking statements. By their
nature, forward-looking statements are subject to numerous risks and
uncertainties, some of which are beyond these parties' control, including the
impact of general economic conditions, industry conditions, volatility of
commodity prices, currency fluctuations, imprecision of reserve estimates,
environmental risks, competition from other industry participants, the lack of
availability of qualified personnel or management, stock market volatility and
ability to access sufficient capital from internal and external sources.
Readers are cautioned that the assumptions used in the preparation of such
information, although considered reasonable at the time of preparation, may
prove to be imprecise and, as such, undue reliance should not be placed on
forward-looking statements. Peyto's actual results, performance or achievement
could differ materially from those expressed in, or implied by, these
forward-looking statements and, accordingly, no assurance can be given that
any of the events anticipated by the forward-looking statements will transpire
or occur, or if any of them do so, what benefits that Peyto will derive
therefrom. Peyto disclaims any intention or obligation to update or revise any
forward-looking statements, whether as a result of new information, future
events or otherwise.
The Toronto Stock Exchange has neither approved nor disapproved the
information contained herein.
Management's discussion and analysis
This Management's Discussion and Analysis ("MD&A") should be read in
conjunction with the unaudited interim consolidated financial statements for
the period ended June 30, 2005 and the audited consolidated financial
statements of Peyto Energy Trust ("Peyto") for the year ended December 31,
2004. The consolidated financial statements have been prepared in accordance
with Canadian generally accepted accounting principles ("GAAP").
The Trust was created by way of a Plan of Arrangement effective July 1,
2003 which reorganized Peyto Exploration & Development Corp. ("PEDC") from a
corporate entity into a trust. Accordingly, the consolidated financial
statements were reported on a continuity of interests basis. As such,
comparative figures for the periods prior to July 1, 2003 are the financial
results of PEDC. This discussion provides management's analysis of Peyto's
historical financial and operating results and provides estimates of Peyto's
future financial and operating performance based on information currently
available. Actual results will vary from estimates and the variances may be
significant. Readers should be aware that historical results are not
necessarily indicative of future performance. This MD&A was prepared using
information that is current as of August 9, 2005. Additional information about
Peyto, including the most recently filed annual information form is available
at www.sedar.com.
Certain information set forth in this Management's Discussion and
Analysis, including management's assessment of the Trust's future plans and
operations, contains forward-looking statements. By their nature, forward-
looking statements are subject to numerous risks and uncertainties, some of
which are beyond these parties' control, including the impact of general
economic conditions, industry conditions, volatility of commodity prices,
currency fluctuations, imprecision of reserve estimates, environmental risks,
competition from other industry participants, the lack of availability of
qualified personnel or management, stock market volatility and ability to
access sufficient capital from internal and external sources. Readers are
cautioned that the assumptions used in the preparation of such information,
although considered reasonable at the time of preparation, may prove to be
imprecise and, as such, undue reliance should not be placed on forward-looking
statements. Peyto's actual results, performance or achievement could differ
materially from those expressed in, or implied by, these forward-looking
statements and, accordingly, no assurance can be given that any of the events
anticipated by the forward-looking statements will transpire or occur, or if
any of them do so, what benefits that Peyto will derive therefrom. Peyto
disclaims any intention or obligation to update or revise any forward-looking
statements, whether as a result of new information, future events or
otherwise.
Management uses funds from operations to analyze the operating
performance of its energy assets. In order to facilitate comparative analysis,
funds from operations is defined throughout this report as earnings before
bonuses, non cash and non recurring expenses. We believe that funds from
operations is an important parameter to measure the value of an asset when
combined with reserve life. Funds from operations is not a measure recognized
by Canadian generally accepted accounting principles ("GAAP") and does not
have a standardized meaning prescribed by GAAP. Therefore, funds from
operations, as defined by Peyto, may not be comparable to similar measures
presented by other issuers, and investors are cautioned that funds from
operations should not be construed as an alternative to net earnings, cash
flow from operating activities or other measures of financial performance
calculated in accordance with GAAP. Funds from operations cannot be assured
and future distributions may vary.
All references are to Canadian dollars unless otherwise indicated.
Natural gas volumes recorded in thousand cubic feet (mcf) are converted to
barrels of oil equivalent (boe) using the ratio of six (6) thousand cubic feet
to one (1) barrel of oil (bbl).
Recently, proposed new legislation to restrict foreign ownership was
issued in draft form by the Department of Finance and has prompted all trusts,
including Peyto, to review their capital structures. To the best of our
knowledge, Peyto's foreign ownership level currently stands at approximately
21.5 percent, well below the level that would jeopardize Peyto's status as a
mutual fund trust under this proposed legislation. A few trusts have
reorganized, or propose to reorganize, their units into a dual class structure
with the objective of restricting foreign ownership to less than 50 percent
and therefore retaining their status as a mutual fund trust. Peyto is an
active supporter of the efforts of the Canadian Association of Income Funds
(CAIF) which is attempting to have the Department of Finance reconsider
components of the proposed legislation. The Department of Finance has
subsequently announced that they are taking more time to consider the proposed
legislation. The Trust will continue to monitor these developments and if it
is deemed appropriate, propose an amendment to its capital structure.
OVERVIEW
Peyto is a Canadian energy trust involved in the development and
production of natural gas in Alberta's deep basin. As at December 31, 2004, we
had total proved plus probable reserves of 129.5 million barrels of oil
equivalent with a reserve life of 17.2 years as evaluated by our independent
petroleum engineers. Our production is weighted as to approximately 80%
natural gas and 20% natural gas liquids and oil.
The Peyto model is designed to deliver growth in its assets, production
and income, all on a per unit basis. The model is built around three key
principles:
- Using our technical expertise to achieve the best return on
capital employed, through the development of internally generated
drilling projects.
- A low payout ratio designed to efficiently fund our growing
inventory of drilling projects.
- Having an asset base which is made up of high quality long life
natural gas reserves.
Operating results over the last six years indicate that we have
successfully implemented these principles. Our business model makes Peyto a
truly unique energy trust.
QUARTERLY FINANCIAL INFORMATION
-------------------------------------------------------------------------
($000 except per 2005 2004
unit amounts) Q2 Q1 Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Total revenue (net of
royalties) 73,473 72,397 66,024 59,337 53,853 50,197
Funds from operations 66,548 66,636 60,334 54,211 48,548 46,012
Per unit - basic(x) 0.69 0.69 0.65 0.60 0.53 0.51
Per unit - diluted(x) 0.69 0.69 0.65 0.60 0.53 0.51
Earnings (loss) 25,690 37,431 (2,558) 21,650 30,347 24,343
Per unit - basic(x) 0.27 0.39 (0.03) 0.24 0.33 0.27
Per unit - diluted(x) 0.27 0.39 (0.03) 0.24 0.33 0.27
-------------------------------------------------------------------------
-----------------------------------------
($000 except per 2003
unit amounts) Q4 Q3
-----------------------------------------
Total revenue (net of
royalties) 45,901 40,743
Funds from operations 41,371 35,882
Per unit - basic(x) 0.46 0.40
Per unit - diluted(x) 0.46 0.40
Earnings (loss) 6,203 25,445
Per unit - basic(x) 0.07 0.28
Per unit - diluted(x) 0.07 0.28
-----------------------------------------
(x)Note: prior periods restated for 2 for 1 split of trust units
completed May 31, 2005.
RESULTS OF OPERATIONS
Production
-------------------------------------------------------------------------
Three Months Six Months
ended June 30 ended June 30
2005 2004 2005 2004
-------------------------------------------------------------------------
Natural gas (mmcf/d) 106.9 87.8 104.9 82.7
Oil & natural gas liquids
(bbl/d) 4,653 3,918 4,495 3,598
Barrels of oil equivalent
(boe/d) 22,464 18,544 21,990 17,389
-------------------------------------------------------------------------
Natural gas production averaged 106.9 mmcf/d in the second quarter of
2005, 22 percent higher than the 87.8 mmcf/d reported for the same period in
2004. Oil and natural gas liquids production averaged 4,653 bbl/d, an increase
of 19 percent from 3,918 bbl/d reported in the prior year. First half
production increased 26 percent from 17,389 boe/d to 21,990 boe/d. The
production increases are directly attributable to Peyto's ongoing drilling
program.
Commodity Prices
-------------------------------------------------------------------------
Three Months Six Months
ended June 30 ended June 30
2005 2004 2005 2004
-------------------------------------------------------------------------
Natural gas ($/mcf) 8.11 7.70 7.86 7.38
Hedging - gas ($/mcf) (0.11) (0.38) 0.05 0.08
-------------------------------------------------------------------------
Natural gas - after hedging
($/mcf) 8.00 7.32 7.91 7.46
-------------------------------------------------------------------------
Oil and natural gas liquids
($/bbl) 54.88 42.84 56.29 41.48
Hedging - oil ($/bbl) (3.85) (2.77) (3.11) (1.63)
-------------------------------------------------------------------------
Oil and natural gas liquids -
after hedging ($/bbl) 51.03 40.06 53.18 39.85
-------------------------------------------------------------------------
Total Hedging ($/boe) (1.33) (2.36) (0.41) 0.07
-------------------------------------------------------------------------
Our natural gas price before hedging averaged $8.11/mcf during the second
quarter of 2005, an increase of 5 percent from $7.70/mcf reported for the
equivalent period in 2004. Oil and natural gas liquids prices averaged
$54.88/bbl up 28 percent from $42.84/bbl a year earlier. Hedging activity for
the second quarter of 2005 reduced Peyto's price achieved by $1.33/boe.
Expectations are for commodity prices to remain strong relative to historical
pricing.
Revenue
-------------------------------------------------------------------------
Three Months Six Months
ended June 30 ended June 30
($000) 2005 2004 2005 2004
-------------------------------------------------------------------------
Natural gas 78,909 61,466 149,330 111,108
Oil and natural gas liquids 23,236 15,274 45,803 27,166
Hedging gain (loss) (2,718) (3,983) (1,637) 234
-------------------------------------------------------------------------
Total revenue 99,427 72,757 193,496 138,508
-------------------------------------------------------------------------
For the three months ended June 30, 2005, gross revenue increased 37
percent to $99.4 million from $72.8 million for the same period in 2004. The
increase in revenue for the period was a result of increased production
volumes and pricing as detailed in the following table:
-------------------------------------------------------------------------
Three Months ended June 30
2005 2004 Change $million
-------------------------------------------------------------------------
Natural gas
Volume (mcf/d) 106,866 87,753 19,113
Volume (mmcf) 9,724.8 7,985.5 1,739.3 12.7
Price ($/mcf) $8.00 $7.32 $0.68 6.6
Oil & NGL
Volume (bbl/d) 4,653 3,918 735
Volume (mbbl) 423.4 356.6 66.8 2.7
Price ($/bbl) $51.03 $40.06 $10.97 4.6
-------------------------------------------------------------------------
Total revenue ($million) 99.4 72.8 26.6 26.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Six Months ended June 30
2005 2004 Change $million
-------------------------------------------------------------------------
Natural gas
Volume (mcf/d) 104,965 82,743 22,222
Volume (mmcf) 18,998.7 15,059.3 3,939.4 29.4
Price ($/mcf) $7.91 $7.46 $0.45 8.4
Oil & NGL
Volume (bbl/d) 4,496 3,598 897
Volume (mbbl) 813.7 654.9 158.8 6.3
Price ($/bbl) $53.18 $39.85 $13.33 10.8
-------------------------------------------------------------------------
Total revenue ($million) 193.4 138.5 54.9 54.9
-------------------------------------------------------------------------
Royalties
We pay royalties to the owners of the mineral rights with whom we hold
leases, including the provincial government of Alberta. Alberta gas crown
royalties are invoiced on the Crown's share of production based on a monthly
established Alberta Reference Price. The Alberta Reference Price is a monthly
weighted average price of gas consumed in Alberta and gas exported from
Alberta reduced for transportation and marketing allowances.
-------------------------------------------------------------------------
Three Months Six Months
ended June 30 ended June 30
2005 2004 2005 2004
-------------------------------------------------------------------------
Royalties, net of ARTC ($000) 25,954 18,904 47,626 34,457
% of sales 26 26 25 25
$/boe 12.69 11.20 11.19 10.89
-------------------------------------------------------------------------
For the second quarter of 2005, royalties averaged $12.69/boe or
approximately 26 percent of Peyto's total petroleum and natural gas sales. The
royalty rate expressed as a percentage of sales, will fluctuate from period to
period due to the fact that the Alberta Reference Price can differ
significantly from the commodity prices obtained by the Trust.
Operating Costs & Transportation
The Trust's operating expenses include all costs with respect to
day-to-day well and facility operations. Processing and gathering income
related to joint venture and third party gas reduces operating expenses.
-------------------------------------------------------------------------
Three Months Six Months
ended June 30 ended June 30
2005 2004 2005 2004
-------------------------------------------------------------------------
Operating costs ($000)
Field expenses 4,235 3,111 8,061 5,811
Processing and gathering income (1,583) (1,363) (3,045) (2,469)
-------------------------------------------------------------------------
Total operating costs 2,652 1,748 5,016 3,342
-------------------------------------------------------------------------
$/boe 1.30 1.04 1.26 1.06
-------------------------------------------------------------------------
Transportation 1,387 1,249 2,703 2,103
-------------------------------------------------------------------------
$/boe 0.68 0.74 0.68 0.66
-------------------------------------------------------------------------
Operating costs were $2.6 million in the second quarter compared to
$1.7 million during the same period a year earlier. On a unit of production
basis, operating costs averaged $1.30/boe in the second quarter of 2005
compared to $1.04/boe for the second quarter of 2004.
Netbacks
Operating netbacks represent the profit margin associated with the
production and sale of petroleum and natural gas. The primary factors that
produce Peyto's strong netbacks are a low cost structure and the high heat
content of our natural gas that results in higher commodity prices.
-------------------------------------------------------------------------
Three Months Six Months
ended June 30 ended June 30
($/boe) 2005 2004 2005 2004
-------------------------------------------------------------------------
Sale Price 48.64 43.12 47.84 43.77
Less:
Royalties 12.69 11.20 11.97 10.89
Operating costs 1.30 1.04 1.26 1.06
Transportation 0.68 0.74 0.68 0.66
-------------------------------------------------------------------------
Operating netback 33.97 30.14 34.71 31.16
General and administrative 0.10 0.30 0.08 0.23
Interest on long-term debt 1.25 0.99 1.11 0.98
Capital tax 0.06 0.08 0.06 0.07
-------------------------------------------------------------------------
Cash netback 32.56 28.77 33.46 29.88
-------------------------------------------------------------------------
General and Administrative Expenses
-------------------------------------------------------------------------
Three Months Six Months
ended June 30 ended June 30
2005 2004 2005 2004
-------------------------------------------------------------------------
G&A expenses ($000) 1,529 1,146 2,940 2,094
Overhead recoveries (1,320) (640) (2,620) (1,382)
-------------------------------------------------------------------------
Net G&A expenses 209 506 320 712
-------------------------------------------------------------------------
$/boe 0.10 0.30 0.08 0.23
-------------------------------------------------------------------------
General and administrative expenses before overhead recoveries increased
to $1.5 million in the second quarter of 2005, as compared to $1.1 million for
the same period in 2004 primarily due to staffing increases required to manage
our active drilling program and increasing property base. Net of overhead
recoveries associated with our capital expenditures program, general and
administrative costs decreased to $0.10 per boe from $0.30 per boe in 2004.
Interest Expense
-------------------------------------------------------------------------
Three Months ended Six Months ended
June 30 June 30
2005 2004 2005 2004
-------------------------------------------------------------------------
Interest expense ($000) 2,552 1,671 4,422 3,108
$/boe 1.25 0.99 1.11 0.98
-------------------------------------------------------------------------
Second quarter 2005 interest expense was $2.5 million or $1.25/boe
compared to $1.7 million or $0.99/boe a year earlier. During 2005, average
debt levels have increased to partially fund Peyto's capital expenditures
program. Interest rates continue to be favourable and are not expected to
increase substantially in the short term.
Depletion, Depreciation and Accretion
The second quarter 2005 provision for depletion, depreciation and
accretion totaled $14.5 million as compared to $10.3 million for the same
period in 2004. On a unit-of-production basis, depletion, depreciation and
accretion costs averaged $7.08/boe as compared to $5.80/boe in 2004. Increases
or decreases in the depletion rate on a unit-of-production basis are
influenced by the reserves added through Peyto's drilling program.
Income Taxes
The current provision for future income tax increased to $17.7 million
for the first half of 2005 from $9.9 million in 2004. The change is primarily
due to increased profitability resulting from higher production volumes and
commodity prices.
HEDGING
Commodity Price Risk Management
The Trust is a party to certain off balance sheet derivative financial
instruments, including fixed price contracts. The Trust enters into these
contracts with well established counter-parties for the purpose of protecting
a portion of its future revenues from the volatility of oil and natural gas
prices. During the first half of 2005, we recorded a hedging loss of
$1.6 million as compared to a hedging gain $0.2 million in the first half of
2004. A summary of contracts outstanding in respect of the hedging activities
are as follows:
Crude Oil Daily Price
Period Hedged Type Volume (CAD)
-------------------------------------------------------------------------
July 1 to September 30, 2005 Fixed price 250 bbl $54.08/bbl
July 1 to September 30, 2005 Fixed price 350 bbl $56.08/bbl
July 1 to September 30, 2005 Fixed price 200 bbl $59.02/bbl
July 1 to September 30, 2005 Fixed price 200 bbl $53.12/bbl
July 1 to September 30, 2005 Fixed price 100 bbl $54.35/bbl
July 1 to September 30, 2005 Fixed price 200 bbl $62.22/bbl
October 1 to December 31, 2005 Fixed price 300 bbl $54.35/bbl
October 1 to December 31, 2005 Fixed price 250 bbl $57.52/bbl
October 1 to December 31, 2005 Fixed price 200 bbl $52.07/bbl
October 1 to December 31, 2005 Fixed price 200 bbl $53.15/bbl
October 1 to December 31, 2005 Fixed price 200 bbl $55.20/bbl
October 1 to December 31, 2005 Fixed price 200 bbl $60.50/bbl
January 1 to March 31, 2006 Fixed price 300 bbl $53.85/bbl
January 1 to March 31, 2006 Fixed price 200 bbl $54.58/bbl
January 1 to March 31, 2006 Fixed price 200 bbl $57.65/bbl
January 1 to March 31, 2006 Fixed price 200 bbl $58.90/bbl
January 1 to March 31, 2006 Fixed price 200 bbl $65.21/bbl
January 1 to March 31, 2006 Fixed price 100 bbl $69.40/bbl
April 1 to June 30, 2006 Fixed price 200 bbl $64.75/bbl
April 1 to June 30, 2006 Fixed price 200 bbl $64.62/bbl
April 1 to June 30, 2006 Fixed price 200 bbl $68.64/bbl
April 1 to June 30, 2006 Fixed price 300 bbl $76.00/bbl
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
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
Natural Gas Daily Price
Period Hedged Type Volume (CAD)
-------------------------------------------------------------------------
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.71/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.70/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.80/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.45/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.55/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.70/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $7.00/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $7.27/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.42/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.65/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.80/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.90/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $7.01/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $7.11/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $7.40/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $7.50/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $7.60/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $7.70/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $7.80/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $7.91/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $8.01/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $8.15/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $8.22/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $8.32/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $8.50/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $8.72/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $8.55/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $9.00/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $9.75/GJ
April 1 to October 31, 2006 Fixed price 5,000 GJ $7.10/GJ
April 1 to October 31, 2006 Fixed price 5,000 GJ $7.20/GJ
April 1 to October 31, 2006 Fixed price 5,000 GJ $7.30/GJ
April 1 to October 31, 2006 Fixed price 5,000 GJ $7.35/GJ
April 1 to October 31, 2006 Fixed price 5,000 GJ $7.45/GJ
April 1 to October 31, 2006 Fixed price 5,000 GJ $7.61/GJ
April 1 to October 31, 2006 Fixed price 5,000 GJ $7.75/GJ
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
Commodity Price Sensitivity
Our low operating costs, low distribution ratio and long reserve life
reduce our sensitivity to changes in commodity prices.
Currency Risk Management
The Trust is exposed to fluctuations in the Canadian/US dollar exchange
ratio since our natural gas and oil sales are effectively priced in US dollars
and converted to Canadian dollars. Currently we have not entered into any
agreements to manage this specific risk.
Interest Rate Risk Management
The Trust is exposed to interest rate risk in relation to interest
expense on its revolving demand facility. Currently we have not entered into
any agreements to manage this risk. At June 30, 2005, the increase or decrease
in earnings for each 100 bps change in interest rate paid on the outstanding
revolving demand loan amounts to approximately $2.3 million per annum.
LIQUIDITY AND CAPITAL RESOURCES
Funds from Operations
-------------------------------------------------------------------------
Three Months ended Six Months ended
June 30 June 30
($000) 2005 2004 2005 2004
-------------------------------------------------------------------------
Earnings 25,690 30,347 63,121 54,690
Items not requiring cash:
Provision for bonuses 21,118 3,087 25,045 11,611
Future income tax expense 5,261 4,812 17,730 9,929
Depletion, depreciation
& accretion 14,479 10,302 27,288 18,330
-------------------------------------------------------------------------
Funds from operations 66,548 48,548 133,184 94,560
-------------------------------------------------------------------------
For the quarter ended June 30, 2005, funds from operations totaled
$66.5 million or $0.69 per unit, representing a 37 percent increase from the
$48.5 million, or $0.53 per unit during the same period in 2004. Peyto's
policy is to distribute approximately 50% of funds from operations to
unitholders while retaining the balance to fund its growth oriented capital
expenditures program. Our earnings and cash flow are highly sensitive to
changes in commodity prices, exchange rates and other factors that are beyond
our control. Current volatility in commodity prices creates uncertainty as to
our funds from operations and capital expenditure budget. Accordingly, we
assess results throughout the year and revise our operational plans as
necessary to reflect the most current information.
Our revenues will be impacted by drilling success and production volumes
as well as external factors such as the market prices for natural gas and
crude oil and the exchange rate of the Canadian dollar relative to the
US dollar.
Bank Debt
We have an extendible revolving term credit facility with a syndicate of
financial institutions in the amount of $350 million including a $330 million
revolving facility and a $20 million operating facility. Available borrowings
are limited by a borrowing base, which is based on the value of petroleum and
natural gas assets as determined by the lenders. The loan is reviewed annually
and may be extended at the option of the lender for an additional 364 day
period. If not extended, the revolving facility will automatically convert to
a one year and one day non revolving term loan. The loan has therefore been
classified as long term on the balance sheet.
At June 30, 2005, $280 million was drawn under the facility. Working
capital liquidity is maintained by drawing from and repaying the unutilized
credit facility as needed. At June 30, 2005, we had a working capital deficit
of $65.4 million.
We believe that funds generated from our operations, together with
borrowings under our credit facility and proceeds, if any, from equity issued
will be sufficient to finance our current operations and planned capital
expenditure program. We anticipate that our 2005 capital expenditures will be
between $260 and $300 million. In 2005, almost all of Peyto's capital
expenditures are discretionary focused on exploration, development and
acquisition activity. The majority of these expenditures will be employed to
drill, complete and tie-in natural gas wells adjacent to Peyto's existing
infrastructure. Peyto has the flexibility to match planned capital
expenditures to actual cash flow.
Capital
At August 9, 2005, 96,923,916 trust units were outstanding (June 30,
2005 - 96,888,404). On May 31, 2005, Peyto trust units split 2 for 1.
Peyto implemented a Distribution Reinvestment Plan ("DRIP") effective
with the March 2005 distribution whereby eligible unitholders may elect to
reinvest their monthly cash distributions in additional trust units at a 5%
discount to market price. On July 15, 2005 35,512 trust units were issued at a
price of $28.14 per trust unit pursuant to the DRIP.
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 pursuant to DRIP 40,570 1,009,376
-------------------------------------------------------------------------
Balance, June 30, 2005 96,888,404 172,801,915
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Market & Reserves Based Bonuses
The Trust awards bonuses to employees and key consultants. The bonus
structure is comprised of market and reserves based components.
Under the reserves based component, the bonus pool, on an annual basis,
will be initially comprised of 3% of the incremental increase in value, if
any, as adjusted to reflect changes in debt, equity and distributions, of
proved producing reserves calculated using a constant price at December 31 of
the current year and a discount rate of 8%. The independent reserves
evaluation for 2005 will be completed in January 2006. A quarterly provision
for the reserves based bonus is based on internally estimated proved producing
reserves additions using 2005 forecast commodity prices adjusted for changes
in debt, equity and distributions. Proved producing reserves are estimated
based on year-to-date production growth. This methodology can generate interim
results which may vary significantly from the final bonus paid. A provision
for compensation expense of $479,000 was recorded for the first half of 2005.
Under the market based component, rights with a three year vesting period
are allocated to employees and key consultants. The number of rights
outstanding at any time is not to exceed 7% of the total number of trust units
outstanding. At December 31 of each year, all vested rights are automatically
cancelled and, if applicable, paid out in cash. The bonus is calculated as the
number of vested rights multiplied by the total of the market appreciation
(over the price at the date of grant) and associated distributions of a trust
unit for that period. A tax factor of 1.333 is then applied to determine the
amount of the bonus to be paid.
Based on the five day weighted average trading price of the trust units
for the period ended June 30, 2005, compensation costs related to 4.8 million
non-vested rights, with an average grant price of $16.69, total $89.4 million.
The Trust records a non-cash provision for future compensation expense over
the life of the rights. The cumulative provision totals $52.9 million of which
$24.6 million was recorded in the first half of 2005.
Capital Expenditures
Net capital expenditures for the second quarter of 2005 totaled
$58.7 million. Exploration and development related activity represented
$46.4 million or 79% of the total, while expenditures on facilities, gathering
systems and equipment totaled $7.9 million or 13% of the total. The following
table summarizes capital expenditures for the year.
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
($000) 2005 2004 2005 2004
-------------------------------------------------------------------------
Land 2,916 2,152 5,292 2,635
Seismic 1,507 382 2,502 1,360
Drilling - Exploratory &
Development 46,369 26,161 119,896 61,910
Production Equipment,
Facilities & Pipelines 7,910 8,213 30,094 29,127
Acquisitions & Dispositions - 100 - 3,150
Office Equipment 28 59 21 72
-------------------------------------------------------------------------
Total capital expenditures 58,730 37,067 157,805 98,254
-------------------------------------------------------------------------
Cash Distributions
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
2005 2004 2005 2004
-------------------------------------------------------------------------
Funds from operations ($000) 66,548 48,548 133,184 94,560
Distributions ($000) 33,898 23,320 64,370 43,896
Distributions per unit ($)(x) 0.35 0.255 0.665 0.48
Payout ratio (%) 51 48 48 46
-------------------------------------------------------------------------
(x) Note: prior periods restated for 2 for 1 split of trust units
completed May 31, 2005.
Peyto's strategy is to distribute approximately 50 percent of funds from
operations to our unitholders on a monthly basis with the balance being
withheld to fund capital expenditures. Management is prepared to adjust the
payout levels to balance desired distributions with our requirement to
maintain an appropriate capital structure. For Canadian income tax purposes
distributions made are considered a combination of income and return of
capital. The portion that is return of capital reduces the adjusted cost base
of the units.
Contractual Obligations
The Trust is committed to payments under operating leases for office
space as follows:
-------------------------------------------------------------------------
$
-------------------------------------------------------------------------
2005 368,062
2006 953,484
2007 953,484
2008 1,096,641
2009 1,096,641
2010 1,096,641
2011 1,096,641
-------------------------------------------------------------------------
6,661,594
-------------------------------------------------------------------------
-------------------------------------------------------------------------
GUARANTEES/OFF BALANCE SHEET ARRANGEMENTS
The Trust is a party to certain off balance sheet derivative financial
instruments, including fixed price contracts as discussed further in the
Hedging section.
INCOME TAXES
The following sets out a general discussion of the Canadian and US tax
consequences of holding Peyto units as capital property. The summary is not
exhaustive in nature and is not intended to provide legal or tax advice.
Unitholders or potential Unitholders should consult their own legal or tax
advisors as to their particular tax consequences.
Canadian Taxpayers
The Trust qualifies as a mutual fund trust under the Income Tax Act
(Canada) and, accordingly, Trust units are qualified investments for RRSPs,
RRIFs, RESPs and DPSPs. Each year, the Trust is required to file an income tax
return and any taxable income of the Trust is allocated to unitholders.
Unitholders are required to include in computing income their pro-rata
share of any taxable income earned by the Trust in that year. An investor's
adjusted cost base (ACB) in a trust unit equals the purchase price of the unit
less any non taxable cash distributions received from the date of acquisition.
To the extent the unitholders' ACB is reduced below zero, such amount will be
deemed to be a capital gain to the unitholder and the unitholders' ACB will be
brought to nil.
During the first half of 2005, the Trust paid distributions to the
unitholders in the amount of $64.4 million (2004 - $43.9 million) in
accordance with the following schedule:
Production Period Record Date Distribution Date Per Unit(x)
-------------------------------------------------------------------------
January 2005 January 31, 2005 February 15, 2005 $0.095
February 2005 February 28, 2005 March 15, 2005 $0.11
March 2005 March 31, 2005 April 15, 2005 $0.11
April 2005 April 29, 2005 May 13, 2005 $0.11
May 2005 May 31, 2005 June 15, 2005 $0.12
June 2005 June 30, 2005 July 15, 2005 $0.12
(x) Note: prior periods restated for 2 for 1 split of trust units
completed May 31, 2005.
US Taxpayers
US unitholders who receive cash distributions are subject to a 15 percent
Canadian withholding tax, applied to the taxable portion of the distributions
as computed under Canadian tax law. US taxpayers may be eligible for a foreign
tax credit with respect to Canadian withholding taxes paid.
The taxable portion of the cash distributions, if any, is determined by
the Trust in relation to its current and accumulated earnings and profit using
US tax principles. The taxable portion so determined, is considered to be a
dividend for US tax purposes.
The non-taxable portion of the cash distributions is a return of the cost
(or other basis). The cost (or other basis) is reduced by this amount for
computing any gain or loss from disposition. However, if the full amount of
the cost (or other basis) has been recovered, any further non-taxable
distributions should be reported as a gain.
US unitholders are advised to seek legal or tax advice from their
professional advisors.
RISK MANAGEMENT
Investors who purchase our units are participating in the net funds from
operations from a portfolio of western Canadian crude oil and natural gas
producing properties. As such, the funds from operations paid to investors and
the value of the units are subject to numerous risks inherent in the oil and
natural gas industry.
Our expected funds from operations depends largely on the volume of
petroleum and natural gas production and the price received for such
production, along with the associated operating costs. The price we receive
for our oil depends on a number of factors, including West Texas Intermediate
oil prices, Canadian/US currency exchange rates, quality differentials and
Edmonton par oil prices. The price we receive for our natural gas production
is primarily dependent on current Alberta market prices. Peyto has an ongoing
commodity price risk management policy that provides for downside protection
on a portion of its future production while allowing access, in certain cases,
to the upside price movements.
Although our focus is on our internally generated drilling programs, any
acquisition of oil and natural gas assets depends on our assessment of value
at the time of acquisition. Incorrect assessments of value can adversely
affect distributions to unitholders and the value of the units. We employ
experienced staff on our team and perform appropriate levels of due diligence
on our analysis of acquisition targets, including a detailed examination of
reserve reports; if appropriate, re-engineering of reserves for a large
portion of the properties to ensure the results are consistent; site
examinations of facilities for environmental liabilities; detailed examination
of balance sheet accounts; review of contracts; review of prior year tax
returns and modeling of the acquisition to attempt to ensure accretive results
to the unitholders.
Inherent in development of the existing oil and gas reserves are the
risks, among others, of drilling dry holes, encountering production or
drilling difficulties or experiencing high decline rates in producing wells.
To minimize these risks, we employ experienced staff to evaluate and operate
wells and utilize appropriate technology in our operations. In addition, we
use prudent work practices and procedures, safety programs and risk management
principles, including insurance coverage against potential losses.
The value of our Trust units is based on among other things, the
underlying value of the oil and natural gas reserves. Geological and
operational risks can affect the quantity and quality of reserves and the cost
of ultimately recovering those reserves. Lower oil and gas prices increase the
risk of write downs on our oil and gas property investments. In order to
mitigate this risk, our proven and probable oil and gas reserves are evaluated
each year by a firm of independent reservoir engineers. The reserves committee
of the Board of Directors reviews and approves the reserve report.
Our access to markets may be restricted at times by pipeline or
processing capacity. We minimize these risks by controlling as much of our
processing and transportation activities as possible and ensuring
transportation and processing contracts are in place with reliable cost
efficient counter parties.
The petroleum and natural gas industry is subject to extensive controls,
regulatory policies and income and resource taxes imposed by various levels of
government. These regulations, controls and taxation policies are amended from
time to time. We have no control over the level of government intervention or
taxation in the petroleum and natural gas industry. However, we operate in
such a manner to ensure that we are in compliance with all applicable
regulations and are able to respond to changes as they occur.
The petroleum and natural gas industry is subject to both environmental
regulations and an increased environmental awareness. We have reviewed our
environmental risks and are, to the best of our knowledge, in compliance with
the appropriate environmental legislation and have determined that there is no
current material impact on our operations.
We are subject to financial market risk. In order to maintain substantial
rates of growth, we must continue reinvesting in, drilling for or acquiring
petroleum and natural gas. Our capital expenditure program is funded primarily
through funds from operations, debt and when appropriate, through the issuance
of equity.
CRITICAL ACCOUNTING ESTIMATES
Reserve Estimates
Estimates of oil and natural gas reserves, by necessity, are projections
based on geologic and engineering data, and there are uncertainties inherent
to the interpretation of such data as well as the projection of future rates
of production and the timing of development expenditures. Reserve engineering
is an analytical process of estimating underground accumulations of oil and
natural gas that can be difficult to measure. The accuracy of any reserve
estimate is a function of the quality of available data, engineering and
geological interpretation and judgment. Estimates of economically recoverable
oil and natural gas reserves and future net cash flows necessarily depend upon
a number of variable factors and assumptions, such as historical production
from the area compared with production from other producing areas, the assumed
effects of regulations by governmental agencies and assumptions governing
future oil and natural gas prices, future royalties and operating costs,
development costs and workover and remedial costs, all of which may in fact
vary considerably from actual results. For these reasons, estimates of the
economically recoverable quantities of oil and natural gas attributable to any
particular group of properties, classifications of such reserves based on risk
recovery, and estimates of the future net cash flows expected 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 reserves based bonus. Actual production, revenues and
expenditures with respect to the Trust's reserves will likely vary from
estimates, and such variances may be material.
The Trust's estimated quantities of proved and probable reserves at
December 31, 2004 were audited by independent petroleum engineers Paddock
Lindstrom & Associates Ltd. Paddock has been evaluating reserves in this area
and for Peyto for 6 consecutive years.
Depletion and Depreciation Estimate
We follow the full cost method of accounting for petroleum and natural
gas operations whereby all costs of exploring for and developing petroleum and
natural gas reserves are capitalized. Such costs include land acquisition
costs, geological and geophysical costs, carrying charges on non-producing
properties, costs of drilling both productive and non productive wells and
overhead charges directly related to acquisition, exploration and development
activities.
All costs of exploring for and developing petroleum and natural gas
reserves, together with the costs of production equipment, are depleted and
depreciated on the unit of production method based on estimated gross proven
reserves. Petroleum and natural gas reserves and production are converted into
equivalent units based upon estimated relative energy content (6 mcf to 1
barrel of oil).
Costs of acquiring unproved properties are initially excluded from
depletion calculations. These unevaluated properties are assessed periodically
to ascertain whether impairment has occurred. When proven reserves are
assigned or the property is considered to be impaired, the cost of the
property or the amount of the impairment is added to costs subject to
depletion calculations.
Full Cost Accounting Ceiling Test
The carrying value of property, plant and equipment is reviewed at least
annually for impairment. Impairment occurs when the carrying value of the
assets is not recoverable by the future undiscounted cash flows. The ceiling
test is based on estimates of proved reserves, production rates, estimated
future petroleum and natural gas prices and costs and other relevant
assumptions. By their nature, these estimates are subject to measurement
uncertainty and the impact on the financial statements could be material. Any
impairment would be charged as additional depletion and depreciation expense.
Asset Retirement Obligation
The asset retirement obligation is estimated based on existing laws,
contracts or other policies. The fair value of the obligation is based on
estimated future costs for abandonment and reclamation discounted at a credit
adjusted risk free rate. The liability is adjusted each reporting period to
reflect the passage of time, with the accretion charged to earnings and for
revisions to the estimated future cash flows. By their nature, these estimates
are subject to measurement uncertainty and the impact on the financial
statements could be material.
Future Market Based Bonus
The provision for future market based bonus is estimated based on current
market conditions, distribution history and on the assumption that all
outstanding rights will be paid out according to the vesting schedule. The
conditions at the time of vesting could vary significantly from the current
conditions and may have a material effect on the calculation.
Reserves Based Bonus
The reserves based bonus is calculated based on the year end independent
reserves evaluation which will be completed in January 2006. A quarterly
provision for the reserves based bonus is based on estimated proved producing
reserves additions adjusted for changes in debt, equity and distributions.
Actual proved producing reserves additions and forecasted commodity prices
could vary significantly from those estimated and may have a material effect
on the calculation.
Income Taxes
The determination of the Trust's income and other tax liabilities
requires interpretation of complex laws and regulations often involving
multiple jurisdictions. All tax filings are subject to audit and potential
reassessment after the lapse of considerable time. Accordingly, the actual
income tax liability may differ significantly from that estimated and
recorded.
CHANGES IN ACCOUNTING POLICIES
None
ADDITIONAL INFORMATION
Additional information relating to Peyto Energy Trust can be found on
SEDAR at www.sedar.com and www.peyto.com.
Quarterly information
-------------------------------------------------------------------------
2005 2004
Q2 Q1 Q4 Q3 Q2
-------------------------------------------------------------------------
Operations
Production
Natural gas
(mcf/d) 106,866 103,043 97,968 91,782 87,753
Oil & NGLs
(bbl/d) 4,653 4,337 4,360 3,967 3,918
Barrels of oil
equivalent
(boe/d
(at) 6:1) 22,464 21,511 20,688 19,264 18,544
Average product
prices
Natural gas
($/mcf) 8.00 7.81 7.58 7.00 7.32
Oil & natural
gas liquids
($/bbl) 51.03 55.52 46.82 43.13 40.06
Average operating
expenses ($/boe) 1.30 1.22 1.03 1.08 1.04
Average
transportation
costs ($/boe) 0.68 0.68 0.77 0.68 0.74
Field netback
($/boe) 33.97 35.50 32.90 31.72 30.14
General &
administrative
expense ($/boe) 0.10 0.06 0.01 0.05 0.30
Interest expense
($/boe) 1.25 0.97 1.03 1.03 0.99
Financial
($000 except
per unit)
Revenue 99,427 94,069 87,127 74,866 72,757
Royalties
(net of ARTC) 25,954 21,672 21,103 15,529 18,904
Funds from
operations 66,548 66,636 60,334 54,211 48,548
Funds from
operations
per unit(x) 0.69 0.69 0.65 0.60 0.53
Cash distri-
butions 33,898 30,472 26,443 23,320 23,320
Cash distri-
butions
per unit(x) 0.35 0.315 0.285 0.255 0.255
Percentage of
funds from
operations
distributed 51% 46% 44% 43% 48%
Earnings 25,690 37,431 (2,558) 21,650 30,347
Earnings per
diluted
unit(x) 0.27 0.39 (0.03) 0.24 0.33
Capital
expenditures 58,730 99,074 76,953 55,565 37,067
Weighted
average trust
units
out-
standing(x) 96,848,988 96,664,210 92,494,022 91,450,544 91,450,544
(x) Note: prior periods restated for 2 for 1 split of trust units
completed May 31, 2005.
Peyto Energy Trust
Consolidated Balance Sheets
(unaudited)
June 30, December 31,
2005 2004
$ $
-------------------------------------------------------------------------
Assets
Current
Cash 6,416,561 -
Accounts receivable 52,692,058 58,992,005
Due from private placements - 27,080,066
Prepaid expenses and deposits 4,562,419 5,262,778
-------------------------------------------------------------------------
63,671,038 91,334,849
Property, plant and equipment (Notes 2 and 3) 662,392,862 531,241,786
-------------------------------------------------------------------------
726,063,900 622,576,635
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities and Unitholders' Equity
Current
Accounts payable and accrued liabilities 76,836,712 124,753,199
Capital taxes payable 371,533 483,081
Cash distributions payable 10,627,311 9,067,811
Provision for future market and reserves
based bonus 41,205,841 22,298,937
-------------------------------------------------------------------------
129,041,397 156,603,028
-------------------------------------------------------------------------
Long-term debt (Note 3) 280,000,000 180,000,000
Provision for future market based bonus 12,258,916 6,121,097
Asset retirement obligations 3,963,600 3,328,834
Future income taxes 88,404,993 70,675,002
-------------------------------------------------------------------------
384,627,509 260,124,933
-------------------------------------------------------------------------
Unitholders' equity
Unitholders' capital (Note 4) 172,801,915 138,953,026
Units to be issued (Note 4) 999,298 27,052,850
Accumulated earnings 237,479,025 174,358,093
Accumulated cash distributions (Note 5) (198,885,244) (134,515,295)
-------------------------------------------------------------------------
212,394,994 205,848,674
-------------------------------------------------------------------------
726,063,900 622,576,635
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
On behalf of the Board:
(signed) "Michael MacBean" (signed) "Donald T. Gray"
Director Director
Peyto Energy Trust
Consolidated Statements of Earnings and Accumulated Earnings
(unaudited)
Three Months Ended June 30 Six Months Ended June 30
2005 2004 2005 2004
$ $ $ $
-------------------------------------------------------------------------
Revenue
Petroleum and
natural gas sales,
net 73,472,840 53,853,189 145,869,788 104,050,585
-------------------------------------------------------------------------
Expenses
Operating (Note 6) 2,652,209 1,747,800 5,015,582 3,341,903
Transportation 1,386,829 1,248,879 2,702,996 2,102,775
General and
administrative 209,031 506,276 319,674 711,828
Future market and
reserves based
bonus provision 21,117,684 3,086,691 25,044,723 11,611,492
Interest 2,551,745 1,671,280 4,422,402 3,107,813
Depletion,
depreciation and
accretion
(Note 2) 14,479,191 10,302,078 27,288,487 18,329,732
-------------------------------------------------------------------------
42,396,689 18,563,004 64,793,864 39,205,543
-------------------------------------------------------------------------
Earnings before
taxes 31,076,151 35,290,185 81,075,924 64,845,042
-------------------------------------------------------------------------
Taxes
Future income
tax expense 5,260,992 4,812,443 17,729,992 9,928,707
Capital tax expense 125,000 130,532 225,000 226,018
-------------------------------------------------------------------------
5,385,992 4,942,975 17,954,992 10,154,725
-------------------------------------------------------------------------
Net earnings for
the period 25,690,159 30,347,210 63,120,932 54,690,317
Accumulated
earnings,
beginning of
period 211,788,866 124,919,566 174,358,093 100,576,459
-------------------------------------------------------------------------
Accumulated
earnings, end
of period 237,479,025 155,266,776 237,479,025 155,266,776
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per unit
(Note 4)
Basic 0.27 0.33 0.65 0.60
Diluted 0.27 0.33 0.65 0.60
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
Peyto Energy Trust
Consolidated Statements of Cash Flows
(Unaudited)
Three Months Ended June 30 Six Months Ended June 30
2005 2004 2005 2004
$ $ $ $
-------------------------------------------------------------------------
Cash provided by
(used in)
Operating Activities
Net earnings for
the period 25,690,159 30,347,210 63,120,932 54,690,317
Items not requiring
cash:
Future income
tax expense 5,260,992 4,812,443 17,729,992 9,928,707
Depletion,
depreciation and
accretion 14,479,191 10,302,078 27,288,487 18,329,732
Change in non-cash
working capital
related to
operating
activities 10,854,377 8,850,032 1,153,941 6,004,491
-------------------------------------------------------------------------
56,284,719 54,311,763 109,293,352 88,953,247
-------------------------------------------------------------------------
Financing Activities
Issue of trust
units, net of
costs 2,874,617 - 7,795,337 -
Distribution
payments (33,897,533) (23,319,918) (64,369,949) (43,896,330)
Increase in
bank debt 70,000,000 20,000,000 100,000,000 30,000,000
Change in non-cash
working capital
related to
financing
activities 470,546 914,505 28,639,566 9,977,133
-------------------------------------------------------------------------
39,447,630 (2,405,413) 72,064,954 (3,919,197)
-------------------------------------------------------------------------
Investing Activities
Additions to
property, plant
and equipment (58,730,387) (37,067,232) (157,804,797) (98,254,635)
Change in non-cash
working capital
related to
investing
activities (30,585,401) (32,788,210) (17,136,948) (7,370,633)
-------------------------------------------------------------------------
(89,315,788) (69,855,442) (174,941,745) (105,625,268)
-------------------------------------------------------------------------
Net increase
(decrease) in
cash 6,416,561 (17,949,092) 6,416,561 (20,591,218)
Cash, beginning
of period - 17,949,092 - 20,591,218
-------------------------------------------------------------------------
Cash, end of period 6,416,561 - 6,416,561 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplemental cash flow information - Note 8
See accompanying notes
Peyto Energy Trust
Notes to Consolidated Financial Statements
June 30, 2005 and 2004
1. Summary of Significant Accounting Policies
The unaudited interim consolidated financial statements of Peyto
Energy Trust (the "Trust") follow the same accounting policies as the
most recent annual audited financial statements. The interim
consolidated financial statement note disclosures do not include all
of those required by Canadian generally accepted accounting
principles applicable for annual financial statements. Accordingly,
these interim financial statements should be read in conjunction with
the 2004 audited consolidated financial statements.
These financial statements include the accounts of Peyto Energy Trust
and its wholly owned subsidiaries, Peyto Exploration & Development
Corp. and Peyto Operating Trust.
Measurement uncertainty
The amount recorded for depletion and depreciation of property, plant
and equipment, the asset retirement obligation, the ceiling test
calculation and reserve based bonus are based on estimates of gross
proved reserves, production rates, petroleum and natural gas prices,
future costs and other relevant assumptions. By their nature, these
estimates are subject to measurement uncertainty and the effect on
the financial statements of changes in such estimates in future years
could be significant.
2. Property, Plant and Equipment
---------------------------------------------------------------------
June 30, December 31,
2005 2004
---------------------------------------------------------------------
$ $
---------------------------------------------------------------------
Property, plant and equipment 774,738,069 616,422,327
Accumulated depletion and depreciation (112,345,207) (85,180,541)
---------------------------------------------------------------------
662,392,862 531,241,786
---------------------------------------------------------------------
---------------------------------------------------------------------
At June 30, 2005 costs of $28,663,020 (December 31, 2004 -
$28,663,020) related to undeveloped land have been excluded from the
depletion and depreciation calculation.
3. Long-Term Debt
The Trust has a syndicated $350 million extendible revolving credit
facility. The facility is made up of a $20 million working capital
sub-tranche and a $330 million production line. The facilities are
available on a revolving basis for a period of at least 364 days and
upon the term out date may be extended for a further 364 day period
at the request of the Trust, subject to approval by the lenders. In
the event that the revolving period is not extended, the facility is
available on a non-revolving basis for a one year term, at the end of
which time the facility would be due and payable. Outstanding amounts
on this facility bear interest at rates determined by the Trust's
debt to cash flow ratio that range from prime to prime plus 0.75% for
debt to cash flow ratios ranging from less than 1:1 to greater than
2.5:1. A General Security Agreement with a floating charge on land
registered in Alberta is held as collateral by the bank.
4. Unitholders' Capital
Authorized: Unlimited number of voting trust units
Issued and Outstanding
---------------------------------------------------------------------
Number of Amount
Trust Units Shares/Units $
---------------------------------------------------------------------
Balance, December 31, 2004 47,725,272 138,953,026
Trust units issued by private placement 670,000 31,586,375
Trust unit issue costs - (103,010)
Trust units issued pursuant to DRIP 28,645 1,356,148
Trust units issued pursuant to
2 for 1 split 48,423,917 -
Trust units issued pursuant to DRIP 40,570 1,009,376
---------------------------------------------------------------------
Balance, June 30, 2005 96,888,404 172,801,915
---------------------------------------------------------------------
---------------------------------------------------------------------
Units to be Issued
The Trust implemented a Distribution Reinvestment Plan ("DRIP")
effective for the March 2005 distribution. The DRIP provides eligible
holders of trust units of Peyto the opportunity to accumulate
additional trust units by reinvesting their cash distributions paid
by Peyto. The cash distributions are reinvested at the discretion of
Peyto, either by acquiring trust units issued from treasury at a 5%
discount to the average market price or by acquiring trust units at
prevailing market rates. On July 15, 2005, 35,512 trust units were
issued from treasury at a price of $28.14 per trust unit pursuant to
the Plan.
Per Unit Amounts
Earnings per unit have been calculated based upon the weighted
average number of units outstanding during the period of 96,848,988
(2004 - 91,450,544; restated for 2 for 1 split of trust units May 31,
2005). There are no dilutive instruments outstanding.
5. Accumulated Cash Distributions
Peyto's strategy is to distribute approximately 50 percent of funds
from operations to our unitholders on a monthly basis with the
balance being withheld to fund capital expenditures. Management is
prepared to adjust the payout levels to balance desired distributions
with our requirement to maintain an appropriate capital structure.
During the six-month period ended June 30, 2005, the Trust paid
distributions to the unitholders in the aggregate amount of
$64.4 million (2004 - $43.9 million) in accordance with the following
schedule:
Production Distribution
Period Record Date Date Per Unit(x)
---------------------------------------------------------------------
January 2005 January 31, 2005 February 15, 2005 $0.095
February 2005 February 28, 2005 March 13, 2005 $0.11
March 2005 March 31, 2005 April 15, 2005 $0.11
April 2005 April 29, 2005 May 15, 2005 $0.11
May 2005 May 31, 2005 June 15, 2005 $0.12
June 2005 June 30, 2005 July 15, 2005 $0.12
(x) Note: prior period restated for 2 for 1 split of trust units
completed May 31, 2005.
6. Operating Expenses
The Trust's operating expenses include all costs with respect to
day-to-day well and facility operations. Processing and gathering
income related to joint venture and third party natural gas reduces
operating expenses.
Three Months Ended Six Months Ended
June 30 June 30
2005 2004 2005 2004
$ $ $ $
---------------------------------------------------------------------
Field expenses 4,235,214 3,110,787 8,060,981 5,811,078
Processing and
gathering
income (1,583,005) (1,362,987) (3,045,399) (2,469,175)
---------------------------------------------------------------------
Total operating
costs 2,652,209 1,747,800 5,015,582 3,341,903
---------------------------------------------------------------------
---------------------------------------------------------------------
7. Financial Instruments
The Trust is a party to certain off balance sheet derivative
financial instruments, including fixed price contracts. The Trust
enters into these contracts with well established counterparties for
the purpose of protecting a portion of its future earnings and cash
flows from operations from the volatility of petroleum and natural
gas prices. The Trust believes the derivative financial instruments
are effective as hedges, both at inception and over the term of the
instrument, as the term and notional amount do not exceed the Trust's
firm commitment or forecasted transaction and the underlying basis of
the instrument correlates highly with the Trust's exposure. A summary
of contracts outstanding in respect of the hedging activities at
June 30, 2005 is as follows:
Crude Oil Daily Price
Period Hedged Type Volume (CAD)
---------------------------------------------------------------------
July 1 to September 30, 2005 Fixed price 250 bbl $54.08/bbl
July 1 to September 30, 2005 Fixed price 350 bbl $56.08/bbl
July 1 to September 30, 2005 Fixed price 200 bbl $59.02/bbl
July 1 to September 30, 2005 Fixed price 200 bbl $53.12/bbl
July 1 to September 30, 2005 Fixed price 100 bbl $54.35/bbl
July 1 to September 30, 2005 Fixed price 200 bbl $62.22/bbl
October 1 to December 31, 2005 Fixed price 300 bbl $54.35/bbl
October 1 to December 31, 2005 Fixed price 250 bbl $57.52/bbl
October 1 to December 31, 2005 Fixed price 200 bbl $52.07/bbl
October 1 to December 31, 2005 Fixed price 200 bbl $53.15/bbl
October 1 to December 31, 2005 Fixed price 200 bbl $55.20/bbl
October 1 to December 31, 2005 Fixed price 200 bbl $60.50/bbl
January 1 to March 31, 2006 Fixed price 300 bbl $53.85/bbl
January 1 to March 31, 2006 Fixed price 200 bbl $54.58/bbl
January 1 to March 31, 2006 Fixed price 200 bbl $57.65/bbl
January 1 to March 31, 2006 Fixed price 200 bbl $58.90/bbl
January 1 to March 31, 2006 Fixed price 200 bbl $65.21/bbl
January 1 to March 31, 2006 Fixed price 100 bbl $69.40/bbl
April 1 to June 30, 2006 Fixed price 200 bbl $64.75/bbl
April 1 to June 30, 2006 Fixed price 200 bbl $64.62/bbl
April 1 to June 30, 2006 Fixed price 200 bbl $68.64/bbl
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
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
Natural Gas Daily Price
Period Hedged Type Volume (CAD)
---------------------------------------------------------------------
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.71/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.70/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.80/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.45/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.55/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.70/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $7.00/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $7.27/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.42/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.65/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.80/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $6.90/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $7.01/GJ
April 1 to October 31, 2005 Fixed price 5,000 GJ $7.11/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $7.40/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $7.50/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $7.60/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $7.70/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $7.80/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $7.91/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $8.01/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $8.15/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $8.22/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $8.32/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $8.50/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $8.72/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $8.55/GJ
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $9.00/GJ
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
As at June 30, the Trust had committed to the future sale of 489,000
barrels of crude oil at an average price of $59.92 per barrel and
26,670,000 gigajoules (GJ) of natural gas at an average price of
$7.48 per GJ or $8.75 per mcf based on the historical heating value
of Peyto's natural gas. These contracts will generate revenue
totaling $228.7 million. Based on the market's estimate of the future
commodity prices as at June 30, 2005 the fair value of these
contracts would be $252.7 million.
Subsequent to June 30, 2005 the Trust entered into the following
contracts:
Crude Oil Daily Price
Period Hedged Type Volume (CAD)
---------------------------------------------------------------------
April 1 to June 30, 2006 Fixed price 300 bbl $76.00/bbl
July 1 to September 30, 2006 Fixed price 300 bbl $75.40/bbl
Natural Gas Daily Price
Period Hedged Type Volume (CAD)
---------------------------------------------------------------------
Nov. 1, 2005 to March 31, 2006 Fixed price 5,000 GJ $9.75/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
8. Supplemental Cash Flow Information
2005 2004
$ $
---------------------------------------------------------------------
Cash interest paid during the year 4,422,402 3,107,813
Cash taxes paid during the year - 211,974
---------------------------------------------------------------------
---------------------------------------------------------------------
Peyto Exploration & Development Corp. Information
Officers
Don Gray
President and Chief Executive Officer
Ken Veres
Vice-President, Exploration
Darren Gee
Vice President, Engineering
Scott Robinson
Vice President, Operations
Sandra Brick
Vice President, Finance
Stephen Chetner
Corporate Secretary
Directors
Ian Mottershead
Rick Braund
Don Gray
Brian Craig
Roberto Bosdachin
John Boyd
Michael MacBean
Auditors
Deloitte & Touche LLP
Solicitors
Burnet, Duckworth & Palmer LLP
Bankers
Bank of Montreal
Union Bank of California
Canadian Imperial Bank of Commerce
Royal Bank of Canada
BNP Paribas
Transfer Agent
Valiant Trust Company
Head Office
2900, 450 - 1st Street SW
Calgary, AB
T2P 5H1
Phone: 403.261.6081
Fax: 403.261.8976
Web: www.peyto.com
Stock Listing Symbol: PEY.un
Toronto Stock Exchange
>>
%SEDAR: 00019597E
