Peyto Exploration & Development Corp. (formerly Peyto Energy Trust) (TSX:PEY) is
pleased to present the operating and financial results for the fourth quarter
and 2010 fiscal year. Peyto had a very successful year in 2010, delivering 28%
growth in production/share, 73% operating margin1, 38% profit margin2, 10%
return on capital and 17% return on equity. Highlights for 2010 include:
- Grew production 47% from 115 MMCFe/d (19,133 boe/d) in Q4 2009 to 169 MMCFe/d
(28,197 boe/d) in Q4 2010 or 28%/share.
- Grew Proved Producing ("PP"), Total Proved ("TP") and Proved plus Probable
Additional ("P+P") reserves by 12%, 21%, and 30% (-3%, 5%, and 13% per share) to
0.7, 1.1, and 1.6 TCFe, respectively. All in FD&A costs for PP, TP and P+P
reserves were $2.10/MCFe ($12.63/boe), $2.35/MCFe and $2.19/MCFe including
changes in future development capital.
- Invested $261 million to build a record 91 MMCFe/d (15,100 boe/d) of new
production at a cost of $17,300/boe/d.
- Reduced industry leading operating costs 15% to $0.35/MCFe ($2.13/boe) from
$0.41/MCFe ($2.48/boe) in 2009.
- Generated $234 million in Funds from Operations ($1.94/share) and $122 million
in Earnings ($1.01/share).
- Reduced net debt 8% to $405 million, leaving $220 million of available
capacity on bank lines of $625 million.
- Distributed $175.3 million to unitholders ($1.44/unit).
- Net Asset value or the NPV per share, debt adjusted (discounted at 5%) of the
Proved plus Probable Additional assets remained at $33/share for the third year
in a row.
2010 in Review
Peyto has now completed its twelfth year of operations. Using the proven
application of horizontal wells with multi-stage fracture treatments, the
company executed a much larger capital program than the previous year but at
similar capital efficiency; building new production for $17,300 per flowing boe.
This meant a record 15,100 boe/d of new production was on-stream by year end. At
the same time, Peyto expanded three of its gas plants to accommodate this new
production and, through continued land capture and development activity,
replaced each drilled location with two new undeveloped locations. The
profitability of this growth was measured by the internal rate of return on the
year's capital investment of $261 million. At year end, this return was
estimated to be 33%. This is not the best annual return ever generated by Peyto,
but considering the low natural gas price environment, it is a very satisfactory
result. Alberta natural gas prices spent three quarters of the year below $4/GJ,
driven by an abundance of supply in North America. In contrast, Edmonton light
oil prices averaged over $75/bbl, meaning oil sold for more than three times
that of natural gas, when converted at 6 mcf to 1 bbl. Peyto's Deep Basin
natural gas stream, which is rich in natural gas liquids like condensate,
propane and butane, was worth 40% more than dry gas due to the difference
between gas and oil prices. Equipped with a low cost advantage and an abundance
of similar undeveloped opportunities, the Peyto team will continue to focus on
delivering profitable growth and an attractive total return with shareholder's
capital in 2011.
(1) Operating Margin is defined as Funds from Operations divided by Revenue
before Royalties but including realized hedging gains (losses).
(2) Profit Margin is defined as Net Earnings for the year divided by
Revenue before Royalties but including realized hedging gains (losses).
Natural gas volumes recorded in thousand cubic feet (mcf) are converted
to barrels of oil equivalent (boe) using the ratio of six (6) thousand
cubic feet to one (1) barrel of oil (bbl). Natural gas liquids and oil
volumes in barrel of oil (bbl) are converted to thousand cubic feet
equivalent (mcfe) using a ratio of one (1) barrel of oil to six (6)
thousand cubic feet. This could be misleading if used in isolation as
it is based on an energy equivalency conversion method primarily
applied at the burner tip and does not represent a value equivalency
at the wellhead.
----------------------------------------------------------------------------
3 Months Ended December 31 %
2010 2009 Change
----------------------------------------------------------------------------
Operations
Production
Natural gas (mcf/d) 148,551 95,467 56%
Oil & NGLs (bbl/d) 3,439 3,222 7%
Thousand cubic feet equivalent
(mcfe/d @ 1:6) 169,184 114,798 47%
Barrels of oil equivalent
(boe/d @ 6:1) 28,197 19,133 47%
Product prices
Natural gas ($/mcf) 4.93 6.17 (20)%
Oil & NGLs ($/bbl) 67.06 60.77 10%
Operating expenses ($/mcfe) 0.31 0.38 (18)%
Transportation ($/mcfe) 0.14 0.11 27%
Field netback ($/mcfe) 4.75 5.64 (16)%
General & administrative
expenses ($/mcfe) 0.13 0.15 (13)%
Interest expense ($/mcfe) 0.36 0.44 (18)%
Financial ($000, except per share)
Revenue 88,633 72,218 23%
Royalties 7,712 7,457 3%
Funds from operations 66,359 53,302 24%
Funds from operations per share 0.53 0.46 15%
Total distributions 46,299 41,371 12%
Total distributions per share 0.36 0.36 -
Payout ratio 70 78 (10)%
Earnings 27,700 33,035 (16)%
Earnings per share 0.22 0.28 (21)%
Capital expenditures 110,561 26,307 320%
Weighted average shares
outstanding 125,726,450 114,920,194 9%
As at December 31
Net debt (before future
compensation expense and
unrealized hedging gains)
Shareholders' equity
Total assets
----------------------------------------------------------------------------
12 Months Ended December 31 %
2010 2009 Change
----------------------------------------------------------------------------
Operations
Production
Natural gas (mcf/d) 122,031 92,718 32%
Oil & NGLs (bbl/d) 3,389 3,028 12%
Thousand cubic feet equivalent
(mcfe/d @ 1:6) 142,366 110,884 28%
Barrels of oil equivalent
(boe/d @ 6:1) 23,728 18,481 28%
Product prices
Natural gas ($/mcf) 5.36 6.44 (17)%
Oil & NGLs ($/bbl) 65.31 50.18 30%
Operating expenses ($/mcfe) 0.35 0.41 (15)%
Transportation ($/mcfe) 0.13 0.11 18%
Field netback ($/mcfe) 5.02 5.60 (10)%
General & administrative
expenses ($/mcfe) 0.12 0.18 (33)%
Interest expense ($/mcfe) 0.39 0.41 (5)%
Financial ($000, except per share)
Revenue 319,426 273,517 17%
Royalties 33,405 25,671 30%
Funds from operations 234,077 202,699 15%
Funds from operations per share 1.94 1.83 6%
Total distributions 175,268 163,263 7%
Total distributions per share 1.44 1.47 (2)%
Payout ratio 75 81 (7)%
Earnings 121,838 152,774 (20)%
Earnings per share 1.01 1.38 (27)%
Capital expenditures 261,484 72,739 259%
Weighted average shares
outstanding 120,548,796 110,555,810 9%
As at December 31
Net debt (before future
compensation expense and
unrealized hedging gains) 404,944 439,860 (8%)
Shareholders' equity 838,646 612,483 37%
Total assets 1,454,575 1,254,113 16%
----------------------------------------------------------------------------
3 Months Ended 12 Months Ended
December 31 December 31
($000) 2010 2009 2010 2009
----------------------------------------------------------------------------
Cash flows from operating
activities 65,545 46,567 222,532 198,688
Change in non-cash working
capital (21,594) 389 (22,297) (4,111)
Change in provision for
performance based compensation (7,456) 1,266 3,978 3,042
Performance based compensation 29,864 5,080 29,864 5,080
----------------------------------------------------------------------------
Funds from operations 66,359 53,302 234,077 202,699
----------------------------------------------------------------------------
Funds from operations per
share 0.53 0.39 1.94 1.83
----------------------------------------------------------------------------
(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. Management believes
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 dividends may vary.
Capital Expenditures
Net capital expenditures for 2010 totaled $261.5 million, a 259% increase from
2009. Invested capital represented 112% of annual funds from operations, as
Peyto aggressively invested in building new production and infrastructure.
Drilling, completions and well connections accounted for $224 million or 86% of
the capital (net of $11.7 million in drilling royalty credits) with facility
expansions accounting for $19 million or 7%. Over 98 sections of new deep basin
lands were purchased with 5% of the total capital, at an average cost of
$195/acre. The majority of this new land is adjacent to Peyto's existing
infrastructure and has identified drilling locations on it.
During the year Peyto spud 52 gross (48.1 net) wells, 45 of which were
horizontal, and brought on production 52 gross (49.2 net) new gas zones. The
average horizontal well cost $3.0 million to drill and $1.6 million to complete,
before any Drilling Royalty Credit or Natural Gas Deep Drilling Program royalty
holiday. Beyond March 31, 2011, a drilling royalty credit of $200 per meter
drilled will no longer be available. After May 1, 2010 the crown revised the
natural gas deep drilling incentive, effectively making all of the formations
that Peyto targets eligible for this holiday. The average 2010 qualifying
horizontal well earned over $1.5 million in royalty holiday.
The Greater Sundance core area was the focus of the majority of the 2010 capital
expenditures with 44 wells drilled and with all three gas plants undergoing
expansion. The remaining capital was focused on liquids rich Cardium gas
development in the northern areas of Kakwa and Cutbank. The following table
summarizes capital expenditures for the year.
----------------------------------------------------------------------------
Three Months ended Twelve Months ended
Dec. 31 Dec. 31
($000) 2010 2009 2010 2009
----------------------------------------------------------------------------
Land 8,049 1,150 12,600 4,115
Seismic 92 644 224 1,470
Drilling - Exploratory &
Development 82,561 27,449 205,567 66,926
Production Equipment,
Facilities & Pipelines 14,766 4,993 49,100 11,417
Acquisitions 5,024 - 5,724 -
Drilling Royalty Credit 69 (7,942) (11,731) (11,342)
Office Equipment - 13 - 153
----------------------------------------------------------------------------
Total Capital Expenditures 110,561 26,307 261,484 72,739
----------------------------------------------------------------------------
Reserves
Peyto was active in the development of existing proved and probable undeveloped
reserves in 2010, as well as identifying and securing new undeveloped reserves.
The following table illustrates the change in reserve volumes and Net Present
Value ("NPV") of future cash flows, discounted at 5%, before income tax, using
forecast pricing.
----------------------------------------------------------------------------
% Change, debt
As at December 31 % Change adjusted per
2010 2009 share (1)
----------------------------------------------------------------------------
Reserves (BCFe)
Proved Producing 664 591 12% 6%
Total Proved 1,078 893 21% 14%
Proved + Probable Additional 1,558 1,199 30% 23%
Net Present Value ($millions)
Discounted at 5%
Proved Producing $ 2,363 $ 2,389 -1% -13%
Total Proved $ 3,404 $ 3,344 2% -10%
Proved + Probable Additional $ 4,738 $ 4,295 10% -3%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Per share or unit, reserves are adjusted for changes in net debt by
converting debt to equity using the Dec 31 unit price of $14.06 for
2009 and share price of $18.49 for 2010. Net Present Values are
adjusted for debt by subtracting net debt from the value prior to
calculating per share amounts.
Note: based on the InSite Petroleum Consultants report effective December 31,
2010. The InSite price forecast is available at www.InSitepc.com. For more
information on Peyto's reserves, refer to the Press Release dated February 16,
2011 announcing the 2010 Year End Reserve Report which is available on the
website at www.peyto.com. The complete statement of reserves data and required
reporting in compliance with NI 51-101 will be included in Peyto's Annual
Information Form to be released in March 2011.
Performance Ratios
The following table highlights some additional annual performance ratios, to be
used for comparative purposes, but it is cautioned that on their own they do not
measure investment success.
----------------------------------------------------------------------------
2010 2009 2008 2007 2006
----------------------------------------------------------------------------
Proved Producing
FD&A ($/mcfe) $ 2.10 $2.26 $2.88 $2.11 $2.95
RLI (yrs) 11 14 14 13 12
Recycle Ratio 2 1.8 2.3 2.8 2
Reserve Replacement 239% 79% 110% 127% 211%
----------------------------------------------------------------------------
Total Proved
FD&A ($/mcfe) $ 2.35 $1.73 $3.17 $1.57 $3.28
RLI (yrs) 17 21 17 16 14
Recycle Ratio 1.8 2.3 2.1 3.7 1.8
Reserve Replacement 456% 422% 139% 175% 194%
Future Development Capital
($ millions) $ 741 $ 446 $ 222 $ 169 $ 166
----------------------------------------------------------------------------
Proved plus Probable
Additional
FD&A ($/mcfe) $ 2.19 $1.47 $3.88 $1.56 $2.90
RLI (yrs) 25 29 23 21 20
Recycle Ratio 1.9 2.8 1.7 3.7 2
Reserve Replacement 790% 597% 122% 117% 220%
Future Development Capital
($millions) $1,310 $ 672 $ 390 $ 321 $ 360
----------------------------------------------------------------------------
- FD&A (finding, development and acquisition) costs are used as a measure of
capital efficiency and are calculated by dividing the capital costs for the
period, including the change in undiscounted future development capital ("FDC"),
by the change in the reserves, incorporating revisions and production, for the
same period (eg. Total Proved ($261.5+$295)/(179.7-148.9+8.661) = $14.09/boe or
$2.35/mcfe).
- The reserve life index (RLI) is calculated by dividing the reserves (in boes)
in each category by the annualized average production rate in boe/year (eg.
Proved Producing 110,619/(28.197x365) = 11). Peyto believes that the most
accurate way to evaluate the current reserve life is by dividing the proved
developed producing reserves by the actual fourth quarter average production.
In Peyto's opinion, for comparative purposes, the proved developed producing
reserve life provides the best measure of sustainability.
- The Recycle Ratio is calculated by dividing the field netback per MCFe, before
hedging, by the FD&A costs for the period (eg. Proved Producing
(($4.17)/$2.10=2.0). The recycle ratio is comparing the netback from existing
reserves to the cost of finding new reserves and may not accurately indicate
investment success unless the replacement reserves are of equivalent quality as
the produced reserves.
- The reserve replacement ratio is determined by dividing the yearly change in
reserves before production by the actual annual production for the year (eg.
Total Proved ((179.7-148.86+8.661)/8.661) = 4.56).
Value Creation/Reconciliation
In order to measure the success of the 2010 capital program, it is necessary to
quantify the total amount of value created during the year and compare that to
the total amount of capital invested. At Peyto's request, and for the benefit of
shareholders, the independent engineers have run last year's evaluation with
this year's price forecast to remove the change in value attributable to both
commodity prices and changing royalties. This approach isolates the value
created by the Peyto team from the value created (or lost) by those changes
outside of their control. Since the capital investments in 2010 were funded
from a combination of cash flow, debt and equity, it is necessary to know the
change in debt and the change in units (now shares) outstanding to see if the
change in value is truly accretive to shareholders.
At year end 2010, Peyto's estimated net debt had decreased by $35 million to
$405 million while the number of units (now shares) outstanding had increased by
17.7 million to 132.8 million shares. The change in debt includes all of the
capital expenditures, net of Drilling Royalty Credits earned, and the total
fixed and performance based compensation paid out during the year. Although
these estimates are believed to be accurate, they remain unaudited at this time
and are subject to change.
Based on this reconciliation of changes in BT NPV, the Peyto team was able to
create $911 million of Proved Producing, $1.59 billion of Total Proven, and
$2.69 billion of Proved plus Probable Additional undiscounted reserve value,
with $261 million of capital investment. The ratio of capital expenditures to
value creation is what Peyto refers to as the NPV recycle ratio, which is simply
the undiscounted value addition, resulting from the capital program, divided by
the capital investment. For 2010, the Proved Producing NPV recycle ratio is 3.5.
The following table breaks out the value created by Peyto's capital investments
and reconciles the changes in debt adjusted NPV of future net revenues using
forecast prices and costs as at December 31, 2010.
----------------------------------------------------------------------------
Proved Producing Total Proved
($millions)
Discounted at 0% 5% 10% 0% 5% 10%
----------------------------------------------------------------------------
Before Tax Net
Present Value at
Beginning of
Year ($millions)
Dec. 31, 2009
Evaluation using
PLA Jan. 1, 2010
price forecast,
less debt $4,215 $ 1,949 $ 1,138 $ 6,210 $ 2,904 $ 1,687
----------------------------------------------------------------------------
Per Unit
Outstanding at
Dec. 31, 2009
($/unit or
share) $36.62 $ 16.93 $ 9.89 $ 53.95 $ 25.23 $ 14.65
----------------------------------------------------------------------------
2010 sales
(revenue less
royalties and
operating
costs) $ (261) $ (261) $ (261) $ (261) $ (261) $ (261)
Net Change due
to price
forecasts (using
InSite Jan 1,
2011 price
forecast) $ (767) $ (402) $ (271) $(1,155) $ (610) $ (410)
Value Change
due to
discoveries
(additions,
extensions,
transfers,
revisions) $ 911 $ 672 $ 571 $ 1,594 $ 966 $ 711
-----------------------------------------------------------
-----------------------------------------------------------
Before Tax Net
Present Value at
End of Year
($millions)
Dec. 31, 2010
Evaluation using
InSite Jan. 1,
2011 price
forecast, less
debt $4,098 $ 1,958 $ 1,177 $ 6,388 $ 2,999 $ 1,727
----------------------------------------------------------------------------
Per Share
Outstanding at
Dec. 31, 2010
($/share) $30.85 $ 14.75 $ 8.86 $ 48.10 $ 22.58 $ 13.00
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year over Year
Change in Before
Tax NPV/unit or
share (16%) (13%) (10%) (11%) (10%) (11%)
Year over Year
Change in Before
Tax NPV/unit or
share including
Distribution
($1.44/unit) (12%) (4%) 4% (8%) (5%) (1%)
----------------------------------------------------------------------------
------------------------------------------------------
Proved + Probable
Additional
($millions)
Discounted at 0% 5% 10%
------------------------------------------------------
Before Tax Net
Present Value at
Beginning of
Year ($millions)
Dec. 31, 2009
Evaluation using
PLA Jan. 1, 2010
price forecast,
less debt $ 8,598 $3,856 $ 2,188
------------------------------------------------------
Per Unit
Outstanding at
Dec. 31, 2009
($/unit or
share) $ 74.69 $33.49 $ 19.01
------------------------------------------------------
2010 sales
(revenue less
royalties and
operating
costs) $ (261) $ (261) $ (261)
Net Change due
to price
forecasts (using
InSite Jan 1,
2011 price
forecast) $(1,494) $ (754) $ (494)
Value Change
due to
discoveries
(additions,
extensions,
transfers,
revisions) $2,691 $1,493 $ 1,004
-------------------------------------
-------------------------------------
Before Tax Net
Present Value at
End of Year
($millions)
Dec. 31, 2010
Evaluation using
InSite Jan. 1,
2011 price
forecast,
less debt $9,534 $4,333 $ 2,438
------------------------------------------------------
Per Share
Outstanding at
Dec. 31, 2010
($/share) $71.79 $32.63 $ 18.36
------------------------------------------------------
------------------------------------------------------
Year over Year
Change in Before
Tax NPV/unit or
share (4%) (3%) (3%)
Year over Year
Change in Before
Tax NPV/unit or
share including
Distribution
($1.44/unit) (2%) 2% 4%
------------------------------------------------------
Tables may not add due to rounding.
Performance Measures
There are a number of performance measures that are used in the oil and gas
industry in an attempt to evaluate how profitably capital has been invested.
Peyto believes that the value analysis presented above is the best determination
of profitability as it compares the value of what was created relative to what
was invested, or what is termed, the NPV recycle ratio. This is because the NPV
of an oil and gas asset takes into consideration the reserves, the production
forecast, the future royalties and operating costs, future capital and the
current commodity price outlook. In 2010, the Proved Producing NPV recycle ratio
was 3.5 times. This means for each dollar invested, the Peyto team was able to
create 3.5 new dollars of Proved Producing reserve value. The average NPV
Recycle Ratio over the last 5 years is 3.7 times for undiscounted future values
or 2.5 times for future values discounted at 10%. The historic NPV recycle ratio
is presented in the following table.
----------------------------------------------------------------------------
Dec 31, Dec 31, Dec 31, Dec 31, Dec 31,
2010 Value Creation 2010 2009 2008 2007 2006
----------------------------------------------------------------------------
NPV0 Recycle Ratio
Proved Producing 3.5 5.4 2.1 4.7 2.9
Total Proved 6.1 18.9 2.5 5.5 2.9
Proved + Probable Additional 10.3 27.1 2.2 3.8 3.8
----------------------------------------------------------------------------
- NPV0 (net present value) recycle ratio is calculated by dividing the
undiscounted NPV of reserves added in the year by the total capital cost
for the period (eg. Proved Producing ($911/$261.5) = 3.5).
Quarterly Review
Capital expenditures for the fourth quarter 2010 increased to $110.6 million up
320% from Q4 2009, as the company continued to aggressively grow the asset base.
Drilling and completions accounted for $82.6 million while production equipment,
pipelines and facilities accounted for $14.8 million. Land, seismic, and a small
acquisition/joint venture in the Nosehill area made up the balance of the
capital expenditures at $13.2 million.
Daily production for Q4 2010 averaged 169 MMCFe/d (28,197 boe/d) up 47% from 115
MMCFe/d in Q4 2009. Natural gas production of 148.6 mmcf/d and oil and natural
gas liquids production of 3,439 bbls/d combined for the increase. Natural gas
prices, before hedging effects, were 19% lower than Q4 2009 at $3.89/mcf, while
liquids prices were 10% higher at $67.06/bbl. Forward sales of natural gas
contributed a hedging gain of $1.04/mcf in Q4 2010, and resulted in a realized
gas price of $4.93/mcf. Total revenue for Q4 2010 was up 23% from Q4 2009 due to
increased volumes, despite 20% lower overall price realizations.
Fourth quarter 2010 cash costs, comprised of royalties, operating costs,
transportation, G&A and interest were 20% lower than Q4 2009 at $1.44/MCFe.
Higher production volumes were the primary driver of lower overall per unit
costs, although reduced chemical consumption, enhanced royalty incentives, and a
larger capital program with greater overhead recovery also contributed.
Total revenue of $5.70/mcfe ($34.20/boe) in Q4 2010, less cash costs of
$1.44/mcfe, resulted in a cash netback of $4.26/mcfe or $25.58/boe, down 16%
from the prior year. This cash netback to revenue ratio translated into a 75%
operating margin.
Marketing
Alberta monthly natural gas prices averaged less than $4/GJ again in 2010, as
the over supplied North American market persisted. The future prices offered for
natural gas in Canada and the US imply this condition will continue throughout
2011 and into 2012, although more evidence is emerging to suggest this is less
than the price required for the profitable development of the many shale gas
plays in the US. Nonetheless, Peyto's low cost structure and high heat content
natural gas allow the company to be profitable at these prices.
Peyto continues to execute a simple but effective marketing strategy designed to
smooth out the volatility in natural gas prices through future sales. This
strategy was again successful in 2010 as Peyto realized a natural gas price of
$5.36/mcf versus an AECO monthly average price of $4.36/mcf.
Details of the individual contracts are available in Management's Discussion and
Analysis ("MD&A"). As at December 31, 2010, Peyto had committed to the future
sale of 24,010,000 gigajoules (GJ) of natural gas at an average price of $5.07
per GJ or $5.93 per mcf. Had these contracts been closed on December 31, 2010,
the company would have realized a gain in the amount of $27.9 million.
Corporate Conversion
The year 2010 marked Peyto's last year as an energy Trust. On December 8, 2010
Peyto announced the receipt of unitholder and court approvals for its conversion
to a corporation. With unitholders voting in excess of 99.8% in favor of the
plan of arrangement, the conversion became effective on December 31, 2010 and
the common shares of Peyto began trading under the symbol "PEY" on the Toronto
Stock Exchange on January 7, 2011.
The Board of Directors is also pleased to confirm the monthly dividend for the
second quarter of 2011 will remain at $0.06/share.
Activity Update
To date in 2011, six drilling rigs have been active in Peyto's Deep Basin core
areas. The company has drilled and rig released 14 gross (12.5 net) wells, 6
gross (5.4 net) of which were spud during 2010. All the wells drilled to date
are horizontals. Four wells (3.6 net) are currently awaiting completion.
Peyto has brought on-stream 11 gross (9.3 net) new wells since the beginning of
2011. These wells are producing a combined 27 MMCfe/d (4,500 boe/d). Total
company production currently ranges between 192 MMCfe/d (32,000 boe/d) and 198
MMCFe/d (33,000 boe/d) as new wells are at various stages of in-line testing and
tie-in.
As March draws to an end, the six active drilling rigs are expected to be
situated on multi-well drill pads that should allow for continuous operations
during the traditional April and May spring break up months. A 25 MMcf/d
expansion of the Wildhay gas plant is expected to be completed by the end of
May. A major expansion of the Nosehill gas plant will follow in late July and
will involve the addition of 50 MMcf/d of gas processing capacity. These two
expansions will eventually allow for combined production growth of over 75
MMCFe/d (12,500 boe/d).
2011 Outlook
Building on the success of the 2010 capital program, Peyto looks to execute an
even larger capital program in 2011 of $300-$325 million. With an ever growing
inventory of drilling locations and a strict focus on cost control, the Peyto
team will again endeavor to deliver significant profitable growth and real
returns for shareholders. At the same time, a $0.06/month dividend allows Peyto
shareholders to enjoy income along the way.
Conference Call and Webcast
A conference call will be held with the senior management of Peyto to answer
questions with respect to the 2010 fourth quarter and full year financial
results on Thursday, March 10, 2011, at 9:00 a.m. Mountain Standard Time (MST),
or 11:00 a.m. Eastern Standard Time (EST). To participate, please call
1-416-340-2216 (Toronto area) or 1- 866-226-1792 for all other participants. The
conference call will also be available on replay by calling 1-905-694-9451
(Toronto area) or 1-800-408-3053 for all other parties, using passcode 5676357.
The replay will be made available at 11:00 a.m. MST or 1:00 p.m. EST Thursday,
March 10, 2011 until midnight EDT on Thursday, March 17th, 2011. The live
conference call can also be accessed through the internet at
http://events.digitalmedia.telus.com/peyto/031011/index.php.
After this time the conference call will be archived on the Peyto Exploration &
Development Corp. website at www.peyto.com.
Management's Discussion and Analysis
A copy of the fourth quarter report to shareholders, including the Management's
Discussion and Analysis, and audited financial statements and related notes is
available at http://www.peyto.com/news/Q42010MDandA.pdf and will be filed at
SEDAR, www.sedar.com , at a later date.
Annual General Meeting
Peyto's Annual General Meeting of Shareholders is scheduled for 3:00 p.m. on
Wednesday, May 18, 2011 at Livingston Place Conference Centre, +15 level,
222-3rd Avenue SW, Calgary, Alberta.
Shareholders are encouraged to visit the Peyto website at www.peyto.com where
there is a wealth of information designed to inform and educate investors. A
monthly President's Report can also be found on the website which follows the
progress of the capital program and the ensuing production growth.
Darren Gee, President and CEO
March 9, 2011
Certain information set forth in this document and Management's Discussion and
Analysis, including management's assessment of Peyto's future plans and
operations, contains forward-looking statements. By their nature,
forward-looking statements are subject to numerous risks and uncertainties, some
of which are beyond these parties' control, including the impact of general
economic conditions, industry conditions, volatility of commodity prices,
currency fluctuations, imprecision of reserve estimates, environmental risks,
competition from other industry participants, the lack of availability of
qualified personnel or management, stock market volatility and ability to access
sufficient capital from internal and external sources. Readers are cautioned
that the assumptions used in the preparation of such information, although
considered reasonable at the time of preparation, may prove to be imprecise and,
as such, undue reliance should not be placed on forward-looking statements.
Peyto's actual results, performance or achievement could differ materially from
those expressed in, or implied by, these forward-looking statements and,
accordingly, no assurance can be given that any of the events anticipated by the
forward-looking statements will transpire or occur, or if any of them do so,
what benefits Peyto will derive therefrom.
Peyto Exploration & Development Corp.
Consolidated Balance Sheets
($000)
December 31, December 31,
2010 2009
----------------------------------------------------------------------------
Assets
Current
Cash 7,894 -
Accounts receivable (Note 4) 55,876 58,305
Due from private placement (Note 8) 12,423 2,728
Financial derivative instruments (Note 14) 25,247 8,683
Prepaid expenses 3,280 3,787
----------------------------------------------------------------------------
104,720 73,503
----------------------------------------------------------------------------
Financial derivative instruments (Note 14) 2,664 1,253
Prepaid capital - 955
Property, plant and equipment (Note 5) 1,347,191 1,178,402
----------------------------------------------------------------------------
1,349,855 1,180,610
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1,454,575 1,254,113
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities and Shareholders' Equity
Current
Accounts payable and accrued liabilities 113,592 55,890
Cash distributions payable (Note 9) 15,825 13,790
Provision for future performance based
compensation (Note 12) 5,567 2,001
----------------------------------------------------------------------------
134,984 71,681
----------------------------------------------------------------------------
Long-term debt (Note 6) 355,000 435,000
Provision for future performance based
compensation (Note 12) 1,452 1,041
Asset retirement obligations (Note 7) 11,926 10,487
Future income taxes (Note 13) 112,567 123,421
----------------------------------------------------------------------------
480,945 569,949
----------------------------------------------------------------------------
Shareholders' or Unitholders' Equity
Shareholders' capital (Note 8) 754,493 -
Unitholders' capital (Note 8) - 500,407
Common shares to be issued (Note 8) 17,285 2,728
Retained earnings (Note 9) 46,319 99,749
Accumulated other comprehensive income 20,549 9,599
----------------------------------------------------------------------------
66,868 109,348
----------------------------------------------------------------------------
838,646 612,483
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1,454,575 1,254,113
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes
On behalf of the Board:
(signed) "Michael MacBean" (signed) "Darren Gee"
Director Director
Peyto Exploration & Development Corp.
Consolidated Statements of Earnings
($000 except per share amounts)
For the years ended December 31,
2010 2009
----------------------------------------------------------------------------
Revenue
Oil and gas sales 275,081 210,530
Realized gain on hedges 44,345 62,987
Royalties (33,405) (25,671)
----------------------------------------------------------------------------
Petroleum and natural gas sales, net 286,021 247,846
----------------------------------------------------------------------------
Expenses
Operating (Note 10) 18,415 16,736
Transportation 6,954 4,541
General and administrative(Note 11) 6,518 7,292
Performance based compensation (Note 12) 29,864 5,080
Future performance based compensation (Note 12) 3,978 3,042
Interest on long term debt 20,057 16,527
Depletion, depreciation and accretion (Notes 5
and 7) 94,184 73,298
----------------------------------------------------------------------------
179,970 126,516
----------------------------------------------------------------------------
Earnings before taxes 106,051 121,330
----------------------------------------------------------------------------
Taxes
Future income tax recovery (Note 13) 15,787 31,444
----------------------------------------------------------------------------
Earnings for the year 121,838 152,774
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Earnings per share or unit (Note 8)
Basic and diluted 1.01 1.38
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes
Peyto Exploration & Development Corp.
Consolidated Statements of Comprehensive Income
($000)
For the years ended December 31,
2010 2009
----------------------------------------------------------------------------
Earnings for the year 121,838 152,774
Other comprehensive income
Change in unrealized gain on cash flow hedges (net
of future income tax, 2010 - $7.0 million, 2009 ?
$0.3 million) 55,295 42,340
Realized (gain) loss on cash flow hedges (44,345) (62,987)
----------------------------------------------------------------------------
Comprehensive Income 132,788 132,127
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes
Peyto Exploration & Development Corp.
Consolidated Statements of Retained Earnings and Accumulated Other
Comprehensive Income
($000)
For the years ended December 31,
2010 2009
----------------------------------------------------------------------------
Retained earnings, beginning of year 99,749 110,238
Earnings for the year 121,838 152,774
Distributions (Note 9) (175,268) (163,263)
----------------------------------------------------------------------------
Retained earnings, end of year 46,319 99,749
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated other comprehensive income, beginning
of year 9,599 30,246
Other comprehensive income (loss) 10,950 (20,647)
----------------------------------------------------------------------------
Accumulated other comprehensive income, end of year 20,549 9,599
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes
Peyto Exploration & Development Corp.
Consolidated Statements of Cash Flows
($000)
For the years ended December 31,
2010 2009
$ $
----------------------------------------------------------------------------
Cash provided by (used in)
Operating Activities
Earnings for the year 121,838 152,774
Items not requiring cash:
Future income tax recovery (15,787) (31,444)
Depletion, depreciation and accretion 94,184 73,298
Change in non-cash working capital related to
operating activities (Note 16) 22,297 4,060
----------------------------------------------------------------------------
222,532 198,688
----------------------------------------------------------------------------
Financing Activities
Issue of common shares 262,292 94,500
Issuance costs (8,272) (5,106)
Cash distributions paid (162,736) (163,263)
Decrease in bank debt (80,000) (65,000)
Change in non-cash working capital related to
financing activities (Note 16) (7,660) (2,098)
----------------------------------------------------------------------------
3,624 (140,967)
----------------------------------------------------------------------------
Investing Activities
Additions to property, plant and equipment (260,581) (70,624)
Change in non-cash working capital related to
investing activities (Note 16) 42,319 12,903
----------------------------------------------------------------------------
(218,262) (57,721)
----------------------------------------------------------------------------
Net increase in cash 7,894 -
Cash, beginning of year - -
----------------------------------------------------------------------------
Cash, end of year 7,894 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes
Peyto Exploration & Development Corp.
Notes to Consolidated Financial Statements
December 31, 2010 and 2009
1. Nature of Operations
Peyto Exploration & Development Corp. (the "Company" or "Peyto") is a Company
established under the laws of the Province of Alberta. The Shareholders of the
Company are entitled to receive cash dividends paid by the Company and are
entitled to one vote for each common share held at shareholder meetings.
The common shares trade on the TSX under the symbol "PEY.TO". The Company's
principal business activity is the exploration for, development and production
of petroleum and natural gas in western Canada.
On December 31, 2010, Peyto completed the conversion from a trust to a
corporation pursuant to a plan of arrangement under the Business Corporations
Act (Alberta). Peyto Energy Trust (the "Trust") was dissolved and the Company,
together with its subsidiaries, received all of the assets and assumed all of
the liabilities of the Trust. As a result of this conversion, the units of the
Trust were exchanged for common shares of Peyto on a one-for-one basis (see Note
8).
The conversion has been accounted for as a continuity of interests and all
comparative information presented for the pre-conversion period is that of the
Trust. All transaction costs associated with the conversion were expensed as
incurred as general and administration expense.
2. Summary of Significant Accounting Policies
These consolidated financial statements have been prepared by management in
accordance with Canadian generally accepted accounting principles. Because a
precise determination of many assets and liabilities is dependent upon future
events, the preparation of periodic financial statements necessarily involves
the use of estimates and approximations. Accordingly, actual results could
differ from those estimates. The consolidated financial statements have, in
management's opinion, been properly prepared within reasonable limits of
materiality and within the framework of the Company's accounting policies
summarized below.
These consolidated financial statements include the accounts of Peyto
Exploration and Development Corp. and all other Peyto entities.
Cash Equivalents
Cash equivalents include market deposits and similar type instruments, with an
original maturity of three months or less when purchased. The Company did not
hold any cash equivalents at the end of the year.
Joint operations
The Company conducts a portion of its petroleum and natural gas exploration,
development and production activities jointly with others and, accordingly,
these consolidated financial statements reflect only the Company's proportionate
interest in such activities.
Property, plant and equipment
The Company follows the full cost method of accounting for its petroleum and
natural gas properties. All costs related to the acquisition, exploration and
development of petroleum and natural gas reserves are capitalized. Such costs
include lease acquisition costs, geological and geophysical costs, carrying
charges of non-producing properties, costs of drilling both productive and
non-productive wells, the cost of petroleum and natural gas production equipment
and overhead charges related to exploration and development activities. All
other general and administrative costs are expensed as incurred.
The Company evaluates its petroleum and natural gas assets to determine that the
costs are recoverable and do not exceed the fair value of the properties
("ceiling test"). The costs are assessed to be recoverable if the sum of the
undiscounted cash flows expected from the production of proved reserves plus the
cost of unproved properties, less impairment, exceed the carrying value of the
oil and gas assets. If the carrying value of the petroleum and natural gas
properties is not determined to be recoverable, an impairment loss is recognized
to the extent that the carrying value exceeds the sum of the discounted cash
flows expected from the production of proved and probable reserves plus the cost
of unproved properties, less impairment. The discounted cash flows are estimated
using the future product prices and costs and are discounted using a risk-free
rate.
Proceeds from the disposition of petroleum and natural gas properties are
applied against capitalized costs except for dispositions that would change the
rate of depletion and depreciation by 20% or more, in which case a gain or loss
would be recorded.
All costs of acquisition, exploration and development of petroleum and natural
gas reserves (net of salvage value) and estimated costs of future development of
proved undeveloped reserves are depleted and depreciated using the unit of
production method based on estimated gross proved reserves as determined by
independent engineers. For purposes of the depletion and depreciation
calculation, relative volumes of petroleum and natural gas production and
reserves are converted at the energy equivalent conversion rate of six thousand
cubic feet of natural gas to one barrel of crude oil.
Costs of unproved properties are initially excluded from petroleum and natural
gas properties for the purpose of calculating depletion. When proved reserves
are assigned to the property or it is considered to be impaired, the cost of the
property or the amount of the impairment is added to costs subject to depletion.
Depreciation of gas plants and related facilities is calculated on a declining
basis over a 20-year term. Office furniture and equipment are depreciated over
their estimated useful lives at declining balance basis between 20% and 30% per
year.
Asset retirement obligations
The Company records a liability for the fair value of legal obligations
associated with the retirement of long-lived tangible assets in the period in
which they are incurred, normally when the asset is purchased or developed. On
recognition of the liability there is a corresponding increase in the carrying
amount of the related asset known as the asset retirement cost, which is
depleted on a unit of production basis over the life of the reserves. 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. Actual costs incurred upon settlement of the obligations are charged
against the liability.
Hedging
The Company uses derivative financial instruments from time to time to hedge its
exposure to commodity price fluctuations. The Company does not enter into
derivative financial instruments for trading or speculative purposes. All
derivative financial instruments are initiated within the guidelines of the
Company's risk management policy. This includes linking all derivatives to
specific assets and liabilities on the balance sheet or to specific firm
commitments or forecasted transactions. The Company enters into hedges of its
exposure to petroleum and natural gas commodity prices by entering into natural
gas fixed price contracts, when it is deemed appropriate. These derivative
contracts, accounted for as hedges, are recognized on the balance sheet.
Realized gains and losses on these contracts are recognized in petroleum and
natural gas revenue and cash flows in the same period in which the revenues
associated with the hedged transaction are recognized. Premiums paid or received
are deferred and amortized to earnings over the term of the contract. For
financial derivative contracts settling in future periods, a financial asset or
liability is recognized in the balance sheet and measured at fair value, with
changes in fair value recognized in other comprehensive income.
Revenue recognition
Petroleum and natural gas sales are recognized as revenue when title passes to
purchasers, normally at pipeline delivery point for natural gas and at the
wellhead for crude oil.
Measurement uncertainty
The timely preparation of the consolidated financial statements in conformity
with Canadian generally accepted accounting principles requires that management
make estimates and assumptions and use judgment regarding the reported amounts
of assets and liabilities and disclosures of contingent assets and liabilities
at the date of the consolidated financial statements and the reported amounts of
revenues and expenses during the period. Such estimates primarily relate to
unsettled transactions and events as of the date of the consolidated financial
statements. Accordingly, actual results may differ from estimated amounts as
future confirming events occur.
Amounts recorded for depreciation, depletion and amortization, asset retirement
costs and obligations and amounts used for ceiling test and impairment
calculations are based on estimates of gross proved reserves and future costs
required to develop those reserves. By their nature, these estimates of
reserves, including the estimates of future prices and costs, and the related
future cash flows are subject to measurement uncertainty, and the impact in the
consolidated financial statements of future periods could be material.
The amount of compensation expense accrued for future performance-based
compensation arrangements are subject to management's best estimate of whether
or not the performance criteria will be met and what the ultimate payout will
be.
Tax interpretations, regulations and legislation in the various jurisdictions in
which the Company and its subsidiaries operate are subject to change. As such,
income taxes are subject to measurement uncertainty.
Future income taxes
The Company follows the liability method of accounting for income taxes. Under
this method, future income taxes are recorded for the effect of any difference
between the accounting and income tax basis of an asset or liability, using the
substantively enacted income tax rates. Accumulated future income tax balances
are adjusted to reflect changes in income tax rates that are substantively
enacted with the adjustment being recognized in earnings in the period that the
change occurs.
Financial Instruments
All financial instruments must initially be recognized at fair value on the
consolidated balance sheet. The Company has classified each financial instrument
into the following categories: "held for trading"; "loans & receivables"; and
"other liabilities". Subsequent measurement of the financial instruments is
based on their classification. Unrealized gains and losses on held for trading
financial instruments are recognized in earnings. The other categories of
financial instruments are recognized at amortized cost using the effective
interest rate method. The Company has made the following classifications:
----------------------------------------------------------------------------
Financial Assets & Liabilities Category
----------------------------------------------------------------------------
Cash Held for trading
----------------------------------------------------------------------------
Accounts Receivable Loans & receivables
----------------------------------------------------------------------------
Due from Private Placement Loans & receivables
----------------------------------------------------------------------------
Accounts Payable and Accrued Liabilities Other Liabilities
----------------------------------------------------------------------------
Provision for Future Performance Based Compensation Other Liabilities
----------------------------------------------------------------------------
Distributions Payable Other Liabilities
----------------------------------------------------------------------------
Long Term Debt Other Liabilities
----------------------------------------------------------------------------
Financial Derivative Instruments Held for trading
----------------------------------------------------------------------------
Derivative Instruments and Risk Management
Derivative instruments are utilized by the Company to manage market risk against
volatility in commodity prices. The Company's policy is not to utilize
derivative instruments for speculative purposes. The Company has chosen to
designate its existing derivative instruments as cash flow hedges. The Company
assesses, on an ongoing basis, whether the derivatives that are used as cash
flow hedges are highly effective in offsetting changes in cash flows of hedged
items. All derivative instruments are recorded on the balance sheet at their
fair value. The effective portion of the gains and losses is recorded in other
comprehensive income until the hedged transaction is recognized in earnings.
When the earnings impact of the underlying hedged transaction is recognized in
the consolidated statement of earnings, the fair value of the associated cash
flow hedge is reclassified from other comprehensive income into earnings. Any
hedge ineffectiveness is immediately recognized in earnings. The fair values of
forward contracts are based on forward market prices.
Embedded Derivatives
An embedded derivative is a component of a contract that causes some of the cash
flows of the combined instrument to vary in a way similar to a stand-alone
derivative. This causes some or all of the cash flows that otherwise would be
required by the contract to be modified according to a specified variable, such
as interest rate, financial instrument price, commodity price, foreign exchange
rate, a credit rating or credit index, or other variables to be treated as a
financial derivative. The Company has no contracts containing embedded
derivatives.
3. Pending Accounting Pronouncements
International Financial Reporting Standards ("IFRS")
In October 2009, the Accounting Standards Board issued a third and final IFRS
Omnibus Exposure Draft confirming that publicly accountable enterprises will be
required to apply IFRS, in full and without modification, for all financial
periods beginning January 1, 2011. The transition to IFRS at January 1, 2011
requires the restatement, for comparative purposes, of amounts reported by the
Company for the year ended December 31, 2010, including the opening balance
sheet as at January 1, 2010.
4. Accounts Receivable
($000) 2010 2009
----------------------------------------------------------------------------
Accounts receivable - general 48,721 51,150
Accounts receivable - income taxes 7,155 7,155
----------------------------------------------------------------------------
55,876 58,305
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Canada Revenue Agency ("CRA") conducted an audit of Peyto's restructuring costs
incurred in the 2003 trust conversion. On September 25, 2008, the CRA reassessed
on the basis that $41 million of these costs were not deductible and treated
them as an eligible capital amount. Peyto filed a notice of objection and the
CRA confirmed the reassessment. Examinations for discovery have been completed.
A trial date has not been set. The Tax Court of Canada has agreed to both
parties' request to hold Peyto's appeal in abeyance pending a decision of the
Federal Court of Appeal in another taxpayer's appeal. The other appeal raises
issues that are similar in principle to those raised in Peyto's appeal. Based
upon consultation with legal counsel, Management's view is that it is likely
that Peyto's appeal will succeed.
5. Property, Plant and Equipment
($000) 2010 2009
----------------------------------------------------------------------------
Property, plant and equipment 1,886,885 1,624,655
Accumulated depletion and depreciation (539,694) (446,253)
----------------------------------------------------------------------------
1,347,191 1,178,402
----------------------------------------------------------------------------
----------------------------------------------------------------------------
At December 31, 2010 costs of $36.4 million (December 31, 2009 - $26.6 million)
related to undeveloped land have been excluded from the depletion and
depreciation calculation.
The Company performed a ceiling test calculation at December 31, 2010 resulting
in the undiscounted cash flows from proved reserves plus the cost of unproved
properties, less impairment, exceeding the carrying value of petroleum and
natural gas assets. The impairment test was calculated at December 31, 2010
using the following independent engineering consultant's forecasted prices:
Thereafter
2011 2012 2013 2014 2015 (1)
----------------------------------------------------------------------------
Edmonton Ref Price 87.30 90.28 93.83 95.88 97.92 +2.0%
($CDN/bbl)
CDN/US Exchange
rate 0.98 0.97 0.96 0.96 0.96 0.96
----------------------------------------------------------------------------
AECO ($CDN/mmbtu) 4.14 4.71 5.29 5.76 6.27 +2.6%
----------------------------------------------------------------------------
(1) Percentage change for the Edmonton Ref Price and the AECO Price of 2.0%
and 2.6% respectively, represents the average change in future prices
each year after 2015 to the end of the reserve life.
6. Long-Term Debt
The Company has a syndicated $625 million extendible revolving credit facility
with a stated term date of April 30, 2011. The facility is made up of a $20
million working capital sub-tranche and a $605 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 Company, 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 further 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 Company's debt to earnings before interest,
taxes, depreciation, depletion and amortization (EBITDA) ratio that range from
prime to prime plus 1.25% to 2.75% for debt to EBITDA 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. The
average borrowing rate for 2010 was 4.6% (2009 - 3.5%).
7. Asset Retirement Obligations
The total future asset retirement obligations are estimated by Management based
on the Company's net ownership interest in all wells and facilities, estimated
costs to reclaim and abandon the wells and facilities and the estimated timing
of the costs to be incurred in future periods. The Company has estimated the net
present value of its total asset retirement obligations to be $11.9 million as
at December 31, 2010 (2009 - $10.5 million) based on a total future liability of
$39.6 million (2009 - $36.0 million). These payments are expected to be made
over the next 50 years. The Company's credit adjusted risk free rate of 7% and
an inflation rate of 2% were used to calculate the present value of the asset
retirement obligations.
The following table reconciles the change in asset retirement obligations:
($000) 2010 2009
----------------------------------------------------------------------------
Balance, December 31, 2009 10,487 9,479
Increase in liabilities relating to investing
activities 696 341
Accretion expense 743 667
----------------------------------------------------------------------------
Balance, December 31, 2010 11,926 10,487
----------------------------------------------------------------------------
----------------------------------------------------------------------------
8. Shareholders' Capital and Unitholders' Capital
Authorized: Unlimited number of voting common shares or units
Issued and Outstanding
Trust Units (no par value) ($000) Number of Units Amount
----------------------------------------------------------------------------
Balance, December 31, 2008 105,920,194 410,233
----------------------------------------------------------------------------
Trust units issued 9,000,000 94,500
Trust units issuance costs (net of tax) - (4,326)
----------------------------------------------------------------------------
Balance, December 31, 2009 114,920,194 500,407
----------------------------------------------------------------------------
Trust units issued by private placement 196,420 2,728
Trust units issued 13,880,500 218,704
Trust units issuance costs (net of tax) - (8,206)
Trust units issued pursuant to DRIP 746,079 10,558
Trust units issued pursuant to OTUPP 2,132,189 30,302
Exchange for common shares pursuant to the
Arrangement (Note 1) (131,875,382) (754,493)
----------------------------------------------------------------------------
Balance, December 31, 2010 - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Common Shares (no par value) ($000) Number of Shares Amount
----------------------------------------------------------------------------
Issuance of common shares for trust units
pursuant to the Arrangement (Note 1) 131,875,382 754,493
----------------------------------------------------------------------------
Balance, December 31, 2010 131,875,382 754,493
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Units Issued
On November 30, 2010, Peyto closed an offering of 8,314,500 trust units at a
price of $17.30 per trust unit, receiving proceeds of $138.8 million (net of
issuance costs).
On April 27, 2010, Peyto closed an offering of 5,566,000 trust units at a price
of $13.45 per trust unit, receiving proceeds of $71.7 million (net of issuance
costs).
On June 26, 2009, Peyto closed an offering of 9,000,000 trust units at a price
of $10.50 per trust unit, receiving net proceeds of $90.2 million (net of
issuance costs).
On December 31, 2009 the Company completed a private placement of 196,420 common
shares to employees and consultants for net proceeds of $2.7 million ($13.89 per
share). These common shares were issued on January 6, 2010.
Peyto reinstated its amended distribution reinvestment and optional trust unit
purchase plan (the "Amended DRIP Plan") effective with the January 2010
distribution whereby eligible Unitholders may elect to reinvest their monthly
cash distributions in additional trust units at a 5% discount to market price.
The DRIP plan incorporates 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.
Common Shares Issued
On December 31, 2010, Peyto converted all outstanding trust units into common
shares on a one share per trust unit basis. At December 31, 2010 there were
131,875,382 shares outstanding. The DRIP and the OTUPP plans were cancelled
December 31, 2010.
Common Shares to be Issued
On December 31, 2010 the Company completed a private placement of 655,581 common
shares to employees and consultants for net proceeds of $12.4 million ($18.95
per share). These common shares were issued on January 6, 2011.
Subsequent to December 31, 2010, 279,723 common shares (113,527 pursuant to the
DRIP and 166,196 pursuant to the OTUPP) were issued for net proceeds of $4.9
million. Subsequent to the issuance of these shares, 132,810,686 common shares
were outstanding.
Per Share or Per Units Amounts
Earnings per share or unit have been calculated based upon the weighted average
number of common shares outstanding during the year of 120,548,796 (2009 -
110,555,810). There are no dilutive instruments outstanding.
Comprehensive Income
Comprehensive income consists of earnings and other comprehensive income
("OCI"). OCI comprises the change in the fair value of the effective portion of
the derivatives used as hedging items in a cash flow hedge. "Accumulated other
comprehensive income" is a equity category comprised of the cumulative amounts
of OCI.
9. Accumulated Distributions
During the year, the Company paid distributions to the Unitholders in the
aggregate amount of $175.3 million (2009 - $163.3 million total) in accordance
with the following schedule:
Production Period Record Date Distribution Date Per
Share (1)
----------------------------------------------------------------------------
January 2010 January 31, 2010 February 15, 2010 $ 0.12
February 2010 February 28, 2010 March 15, 2010 $ 0.12
March 2010 March 31, 2010 April 15, 2010 $ 0.12
April 2010 April 30, 2010 May 14, 2010 $ 0.12
May 2010 May 31, 2010 June 15, 2010 $ 0.12
June 2010 June 30, 2010 July 15, 2010 $ 0.12
July 2010 July 31, 2010 August 13, 2010 $ 0.12
August 2010 August 31, 2010 September 15, 2010 $ 0.12
September 2010 September 30, 2010 October 15, 2010 $ 0.12
October 2010 October 31, 2010 November 15, 2010 $ 0.12
November 2010 November 30, 2010 December 15, 2010 $ 0.12
December 2010 December 31, 2010 January 15, 2011 $ 0.12
----------------------------------------------------------------------------
(1) Distributions per trust unit reflect the per trust unit amounts
declared monthly to Unitholders.
Retained Earnings and Distributions
($000) 2010 2009
----------------------------------------------------------------------------
Retained earnings, beginning of year 1,072,209 919,435
Earnings for the year 121,838 152,774
----------------------------------------------------------------------------
Total retained earnings 1,194,047 1,072,209
Total accumulated distributions (1,147,728) (972,460)
----------------------------------------------------------------------------
Retained earnings, end of year 46,319 99,749
----------------------------------------------------------------------------
----------------------------------------------------------------------------
10. Operating Expenses
The Company'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.
($000) 2010 2009
----------------------------------------------------------------------------
Field expenses 28,960 27,487
Processing and gathering income (10,545) (10,751)
----------------------------------------------------------------------------
Total Operating expenses 18,415 16,736
----------------------------------------------------------------------------
----------------------------------------------------------------------------
11. General and Administrative Expenses
General and administrative expenses are reduced by operating and capital
overhead recoveries from operated properties.
($000) 2010 2009
----------------------------------------------------------------------------
General and Administrative expenses 11,063 9,797
Overhead recoveries (4,545) (2,505)
----------------------------------------------------------------------------
Net General and administrative expenses 6,518 7,292
----------------------------------------------------------------------------
----------------------------------------------------------------------------
12. Performance Based Compensation
The Company awards performance based compensation to employees and key
consultants annually. The performance based compensation is comprised of reserve
and market value based components.
Reserve Based Component
The reserves value based component is 4% of the incremental increase in value,
if any, as adjusted to reflect changes in debt, equity, dividends, general and
administrative costs and interest, of proved producing reserves calculated using
a constant price at December 31 of the current year and a discount rate of 8%.
----------------------------------------------------------------------------
($millions except share values) 2010 2009 Change
----------------------------------------------------------------------------
Net present value of proved
producing reserves @ 8%
based on constant Independent
Reservoir Engineers'
2011 price forecast 1,254.0 1,178.0
Net debt before performance based
compensation (392.4) (439.9)
2010 distributions, general and
administration and
interest expense - (201.8)
------------------------
Net value 861.6 536.3
Shares/units outstanding 131.875 115.117
------------------------
Net value per share/unit 6.532 4.658 1.874
Units outstanding at beginning of
year 115.117
------------
Equity adjusted increase in value 215.7
------------
2010 reserve value based
compensation @ 4% 8.6
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Market Based Component
Under the market based component, rights with a three year vesting period are
allocated to employees and key consultants. The number of rights outstanding at
any time is not to exceed 6% of the total number of common shares 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 dividends of a share for that period. The
2010 market based component was based on i) 1.5 million vested rights at an
average grant price of $16.45, average cumulative distributions of $4.67, ii)
0.5 million vested rights at an average grant price of $9.53, average cumulative
distributions of $2.91 and a five day weighted average closing price of $18.95
and iii) 0.7 million vested rights at an average grant price of $13.49, average
cumulative distributions of $1.44 and a ten day weighted average price of
$18.83.
The total amount expensed under these plans was as follows:
($000) 2010 2009
----------------------------------------------------------------------------
Market based compensation 21,236 4,540
Reserve value based compensation 8,628 540
----------------------------------------------------------------------------
Total 29,864 5,080
----------------------------------------------------------------------------
----------------------------------------------------------------------------
For the future market based component, compensation costs as at December 31,
2010 were $4.0 million, which related to 0.5 million non-vested rights with an
average grant price of $9.56 and 1.3 million non-vested rights with an average
grant price of $13.49. (2009 - 1.5 million non-vested rights with an average
grant price of $16.33 and 1.0 million non-vested rights with an average grant
price of $9.55 were $3.0 million). The cumulative provision for future
performance based compensation as at December 31, 2010 was $7.0 million (2009 -
$3.0 million).
13. Future Income Taxes
On December 31, 2010, the Company converted from a publicly traded income trust
to a publicly traded corporation by way of a plan of arrangement (see Note 1).
As a result, for the year ended December 31, 2010, the Company's future income
tax recovery was calculated on the basis of it being a corporation. For the year
ended December 31, 2009, the Company's future income tax recovery was calculated
on the basis of it being a publicly traded income trust in accordance with
legislation applicable to certain income trusts.
($000) 2010 2009
----------------------------------------------------------------------------
Earnings before income taxes 106,051 121,330
Statutory income tax rate 28.00% 29.00%
----------------------------------------------------------------------------
Expected income taxes 29,694 35,186
Increase (decrease) in income taxes from:
Corporate income tax rate change 367 (25,277)
Income distributed by the Trust (40,123) (40,244)
Change in valuation allowance (5,968) (1,040)
Other 243 (69)
----------------------------------------------------------------------------
Future income tax expense (recovery) (15,787) (31,444)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Differences between tax base and reported amounts
for depreciable assets 117,940 126,746
Financial derivative asset 7,361 337
Share issuance costs (2,872) (781)
Future performance based bonuses (1,838) (260)
Provision for asset retirement obligation (2,981) (2,621)
Tax assets previously under valuation allowance (4,968) -
Tax loss carry-forwards recognized (75) -
----------------------------------------------------------------------------
Future income taxes 112,567 123,421
----------------------------------------------------------------------------
----------------------------------------------------------------------------
At December 31, 2010 the Company has tax pools of approximately $884.0 million
(December 31, 2009 - $676.1 million) available for deduction against future
income. The Company has approximately $nil in unrecognized future income tax
assets (December 31, 2009 - $6.0 million) and approximately $0.3 million in loss
carryforwards (December 31, 2009 - $nil) available to reduce future taxable
income.
14. Financial Instruments and Risk Management
Financial Instrument Classification and Measurement
Financial instruments of the Company carried on the Consolidated Balance Sheet
are carried at amortized cost with the exception of cash and financial
derivative instruments, specifically fixed price contracts, which are carried at
fair value. There are no significant differences between the carrying value of
financial instruments and their estimated fair values as at December 31, 2010.
The fair value of the Company's cash and financial derivative instruments are
quoted in active markets. The Company classifies the fair value of these
transactions according to the following hierarchy.
- Level 1 - quoted prices in active markets for identical financial instruments.
- Level 2 - quoted prices for similar instruments in active markets; quoted
prices for identical or similar instruments in markets that are not active; and
model-derived valuations in which all significant inputs and significant and
significant value drivers are observable in active markets.
- Level 3 - valuations derived from valuation techniques in which one or more
significant inputs or significant value drivers are unobservable.
The Company's cash and financial derivative instruments have been assessed on
the fair value hierarchy described above and classified as Level 1.
Fair Values of Financial Assets and Liabilities
The Company's financial instruments include cash, accounts receivable, financial
derivative instruments, due from private placement, current liabilities,
provision for future performance based compensation and long term debt. At
December 31, 2009, the carrying value of cash and financial derivative
instruments are carried at fair value. Accounts receivable, due from private
placement, current liabilities (excluding future income tax) and provision for
future performance based compensation approximate their fair value due to their
short term nature. The carrying value of the long term debt approximates its
fair value due to the floating rate of interest charged under the credit
facility.
Market Risk
Market risk is the risk that changes in market prices will affect the Company's
earnings or the value of its financial instruments. Market risk is comprised of
commodity price risk and interest rate risk. The objective of market risk
management is to manage and control exposures within acceptable limits, while
maximizing returns. The Company's objectives, processes and policies for
managing market risks have not changed from the previous year.
Commodity Price Risk Management
The Company is a party to certain derivative financial instruments, including
fixed price contracts. The Company 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 Company 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 Company's firm commitment or
forecasted transactions and the underlying basis of the instruments correlate
highly with the Company's exposure. A summary of contracts outstanding in
respect of the hedging activities at December 31, 2009 is as follows:
Asset Asset
as at as at
Fair December December
Effective Value 31, 31,
Description Notional (1) Term Rate Level 2010 2009
----------------------------------------------------------------------------
Natural gas 24.01 GJ (2) 2011- 2012 $ 5.07/GJ Level 1 27,911 9,936
financial
swaps
AECO
----------------------------------------------------------------------------
(1) Notional values as at December 31, 2010 (2) Millions of gigajoules
----------------------------------------------------------------------------
Natural Gas Price
Period Hedged Type Daily Volume (CAD)
----------------------------------------------------------------------------
November 1, 2009 to March 31, 2011 Fixed Price 5,000 GJ $ 6.20/GJ
November 1, 2009 to March 31, 2011 Fixed price 5,000 GJ $ 5.81/GJ
April 1, 2010 to March 31, 2011 Fixed Price 5,000 GJ $ 5.28/GJ
April 1, 2010 to March 31, 2011 Fixed Price 5,000 GJ $ 5.29/GJ
April 1, 2010 to March 31, 2011 Fixed Price 5,000 GJ $ 5.555/GJ
April 1, 2010 to March 31, 2011 Fixed Price 5,000 GJ $ 5.70/GJ
April 1, 2010 to March 31, 2011 Fixed Price 5,000 GJ $ 4.55/GJ
April 1, 2010 to March 31, 2012 Fixed Price 5,000 GJ $ 5.67/GJ
April 1, 2010 to March 31, 2012 Fixed Price 5,000 GJ $ 5.82/GJ
November 1, 2010 to March 31, 2011 Fixed Price 5,000 GJ $ 8.91/GJ
November 1, 2010 to March 31, 2011 Fixed Price 5,000 GJ $ 9.15/GJ
November 1, 2010 to March 31, 2012 Fixed Price 5,000 GJ $ 4.10/GJ
April 1, 2011 to October 31, 2011 Fixed Price 5,000 GJ $ 3.50/GJ
April 1, 2011 to March 31, 2012 Fixed Price 5,000 GJ $ 6.20/GJ
April 1, 2011 to March 31, 2012 Fixed Price 5,000 GJ $ 5.00/GJ
April 1, 2011 to March 31, 2012 Fixed Price 5,000 GJ $ 5.12/GJ
April 1, 2011 to October 31, 2012 Fixed Price 5,000 GJ $ 4.05/GJ
April 1, 2011 to October 31, 2012 Fixed Price 5,000 GJ $ 4.15/GJ
November 1, 2011 to March 31, 2012 Fixed Price 5,000 GJ $ 4.50/GJ
----------------------------------------------------------------------------
As at December 31, 2010, the Company had committed to the future sale of
24,010,000 gigajoules (GJ) of natural gas at an average price of $5.07 per GJ or
$5.93per mcf based on the historical heating value of Peyto's natural gas. Had
these contracts been closed on December 31, 2010, the Company would have
realized a gain in the amount of $27.9 million. If the AECO gas price on
December 31, 2010 were to increase by $1/GJ, the unrealized gain on these closed
contracts would change by approximately $24.0 million. An opposite change in
commodity prices rates would result in an opposite impact on earnings which
would have been reflected in other comprehensive income.
Subsequent to December 31, 2010 the Company entered into the following contracts:
Natural Gas Price
Period Hedged Type Daily Volume (CAD)
----------------------------------------------------------------------------
April 1, 2011 to October 31, 2011 Fixed price 5,000 GJ $ 3.80/GJ
April 1, 2011 to October 31, 2012 Fixed price 5,000 GJ $ 4.10/GJ
April 1, 2011 to October 31, 2012 Fixed price 5,000 GJ $ 4.00/GJ
----------------------------------------------------------------------------
Interest rate risk
The Company is exposed to interest rate risk in relation to interest expense on
its revolving credit facility. Currently, the Company has not entered into any
agreements to manage this risk. If interest rates applicable to floating rate
debt were to have increased by 100 bps (1%) it is estimated that the Company's
earnings for the year ended December 31, 2010 would decrease by $4.2 million. An
opposite change in interest rates will result in an opposite impact on earnings.
Credit Risk
A substantial portion of the Company's accounts receivable is with petroleum and
natural gas marketing entities.
Industry standard dictates that commodity sales are settled on the 25th day of
the month following the month of production. The Company generally extends
unsecured credit to purchasers, and therefore, the collection of accounts
receivable may be affected by changes in economic or other conditions and may
accordingly impact the Company'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 Company has not previously
experienced any material credit losses on the collection of accounts receivable.
Of the Company's revenue for the year ended December 31, 2010, approximately 76%
was received from five companies (20%, 18%, 17%, 11% and 10%) (December 31, 2009
- 55%, three companies (21%, 20% and 14%). Of the Company's accounts receivable
for the year ended December 31, 2010, approximately 31% was receivable from
three companies (11%, 10% and 10%) (December 31, 2009 - the Company had no
significant accounts receivable from any one customer). The maximum exposure to
credit risk is represented by the carrying amount on the consolidated balance
sheet. There are no material financial assets that the Company considers past
due and no accounts have been written off.
The Company may be exposed to certain losses in the event of non-performance by
counterparties to commodity price contracts. The Company mitigates this risk by
entering into transactions with counterparties that have investment grade credit
ratings.
Counterparties to financial instruments expose the Company to credit losses in
the event of non-performance. Counterparties for derivative instrument
transactions are limited to high credit-quality financial institutions, which
are all members of our syndicated credit facility.
The Company assesses quarterly if there should be any impairment of financial
assets. At December 31, 2010, there was no impairment of any of the financial
assets of the Company.
Liquidity Risk
Liquidity risk includes the risk that, as a result of operational liquidity
requirements:
- The Company will not have sufficient funds to settle a transaction on the due
date;
- The Company will be forced to sell financial assets at a value which is less
than what they are worth; or
- The Company may be unable to settle or recover a financial asset at all.
The Company's operating cash requirements, including amounts projected to
complete our existing capital expenditure program, are continuously monitored
and adjusted as input variables change. These variables include, but are not
limited to, available bank lines, oil and natural gas production from existing
wells, results from new wells drilled, commodity prices, cost overruns on
capital projects and changes to government regulations relating to prices,
taxes, royalties, land tenure, allowable production and availability of markets.
As these variables change, liquidity risks may necessitate the need for the
Company to conduct equity issues or obtain project debt financing. The Company
also mitigates liquidity risk by maintaining an insurance program to minimize
exposure to certain losses.
The following are the contractual maturities of financial liabilities as at
December 31, 2010:
($000s) less than 1 Year 1-2 Years 2-5 Years Thereafter
----------------------------------------------------------------------------
Accounts payable and accrued
liabilities 113,592
Distributions payable 15,825
Provision for future market and
reserves based bonus 5,567 1,452
Long-term debt (1) 355,000
----------------------------------------------------------------------------
(1) Revolving credit facility renewed annually (see Note 7)
15. Capital Disclosures
The Company's objectives when managing capital are: (i) to maintain a flexible
capital structure, which optimizes the cost of capital at acceptable risk; and
(ii) to maintain investor, creditor and market confidence to sustain the future
development of the business.
The Company manages its capital structure and makes adjustments to it in light
of changes in economic conditions and the risk characteristics of its underlying
assets. The Company considers its capital structure to include Shareholders'
equity, debt and working capital. To maintain or adjust the capital structure,
the Company may from time to time, issue common shares, raise debt and/or adjust
its capital spending to manage its current and projected debt levels. The
Company monitors capital based on the following non-GAAP measures: current and
projected debt to earnings before interest, taxes, depreciation, depletion and
amortization ("EBITDA") ratios, payout ratios and net debt levels. To facilitate
the management of these ratios, the Company prepares annual budgets, which are
updated depending on varying factors such as general market conditions and
successful capital deployment. Currently, all ratios are within acceptable
parameters. The annual budget is approved by the Board of Directors. The
Company is not subject to any external financial covenants.
There were no changes in the Company's approach to capital management from the
previous year.
December 31, December 31,
($000s) 2010 2009
----------------------------------------------------------------------------
Shareholders' equity 838,646 612,483
Long-term debt 355,000 435,000
Working capital deficit (surplus) (1) 30,264 (1,822)
----------------------------------------------------------------------------
1,223,910 1,045,661
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Current assets less current liabilities (includes unrealized hedging
asset of $25.2 million (2009 - $8.7 million))
16. Supplemental Cash Flow Information
Changes in non-cash working capital balances
($000) 2010 2009
----------------------------------------------------------------------------
Accounts receivable 2,429 7,357
Due from private placement (9,695) -
Prepaid expenses 507 (420)
Accounts payable and accrued liabilities 57,703 7,035
Distributions payable 2,035 (2,098)
Provision for future performance based
compensation 3,977 3,042
----------------------------------------------------------------------------
56,956 14,916
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Attributable to operating activities 22,297 4,060
Attributable to financing activities (7,660) (2,098)
Attributable to investing activities 42,319 12,903
----------------------------------------------------------------------------
56,956 14,916
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2010 2009
----------------------------------------------------------------------------
Cash interest paid during the year 20,057 16,527
----------------------------------------------------------------------------
Cash taxes paid during the year - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
17. Contingencies and Commitments
Following is a summary of the Company's commitments related to operating leases
as at December 31, 2010. The Company has no other contractual obligations or
commitments as at December 31, 2010.
($000) December 31, 2010
----------------------------------------------------------------------------
2011 1,043
2012 1,043
2013 1,043
2014 1,043
----------------------------------------------------------------------------
4,172
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Contingent Liability
From time to time, Peyto is the subject of litigation arising out of its
day-to-day 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 position or
results of operations in the period of settlement. 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 or results of operations.
Peyto has been named in a Statement of Claim issued by Canadian Natural
Resources Limited and affiliates ("CNRL"), claiming $13 million in damages for
alleged breaches of duty as operator of jointly owned properties, and an interim
and permanent injunction to prevent Peyto from proceeding with the completion of
a well on those properties. CNRL alleges that Peyto failed to take proper steps
as operator of a joint well (the "Well") on lands that offset 100% Peyto owned
lands. Peyto has filed a Statement of Defense defending the allegations set
forth in the Statement of Claim. The injunction claimed by CNRL was to prevent
Peyto from completing the Well at a target location which had been agreed upon
by both parties. Although claimed in the Statement of Claim, CNRL did not apply
for an interim injunction, and Peyto completed the Well as planned, but no
commercial production was obtained. Affidavits of Records were filed in July,
2006 but CNRL had taken no steps to move the matter forward until February 14,
2007 when it proposed to amend its Statement of Claim to add a subsidiary as an
additional Plaintiff and to particularize further its allegations. 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 the Company's financial position or
results of operations.
18. Related Party Transactions
An officer and director of the Company is a partner of a law firm that provides
legal services to the Company. The fees charged are based on standard rates and
time spent on matters pertaining to the Company and its subsidiaries. For the
year ended December 31, 2010, legal fees totaled $1.4 million (2009 - $0.6
million). As at December 31, 2010, an amount due to this firm of $1.3 million
was included in accounts payable (2009 - $0.5 million).
During the year ended December 31, 2010, a private company controlled by a
director of the Company was paid $10,000 (2009 - $nil) for consulting services.
The transaction with the related party occurred within normal course of business
and has been measured at its exchange amount which is the amount of
consideration established and agreed to with the related party.
Peyto Exploration & Development Corp. Information
Officers
Darren Gee Glenn Booth
President and Chief Executive Officer Vice-President, Land
Scott Robinson David Thomas
Executive Vice-President and Chief Vice-President, Exploration
Operating Officer
Kathy Turgeon Stephen Chetner
Vice-President, Finance and Chief Corporate Secretary
Financial Officer
Directors
Don Gray, Chairman
Rick Braund
Stephen Chetner
Brian Davis
Michael MacBean, Lead Independent Director
Darren Gee
Gregory Fletcher
Scott Robinson
Auditors
Deloitte & Touche LLP
Solicitors
Burnet, Duckworth & Palmer LLP
Bankers
Bank of Montreal
Union Bank, Canada Branch
BNP Paribas (Canada)
Royal Bank of Canada
Canadian Imperial Bank of Commerce
Alberta Treasury Branches
Société Générale (Canada Branch)
HSBC Bank Canada
Canadian Western Bank
Transfer Agent
Valiant Trust Company
Head Office
1500, 250 - 2(nd) Street SW
Calgary, AB
T2P 0C1
Phone: 403.261.6081
Fax: 403.451.4100
Web: www.peyto.com
Stock Listing Symbol: PEY.TO
Toronto Stock Exchange
Orecap Invest (TSXV:OCI)
Historical Stock Chart
From Dec 2024 to Jan 2025
Orecap Invest (TSXV:OCI)
Historical Stock Chart
From Jan 2024 to Jan 2025
