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| Share Name | Share Symbol | Market | Type |
|---|---|---|---|
| Orecap Invest Corp | TSXV:OCI | TSX Venture | Common Stock |
| Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
|---|---|---|---|---|---|---|---|---|---|---|
| 0.00 | 0.00% | 0.06 | 0.055 | 0.065 | 0.06 | 0.06 | 0.06 | 237,000 | 21:00:02 |
Hot Features
Premium
Peyto Exploration & Development Corp. (TSX:PEY) ("Peyto" or the "Company") is
pleased to report a 41% increase in production per share along with operating
and financial results for the third quarter of 2011. Current production of
40,000 boe/d is expected to grow to 42,000 boe/d by year end, 20% greater than
original guidance. This quarter now marks the eighth consecutive quarter of
production per share growth. Additional third quarter 2011 highlights include:
-- Production increased from 143 MMcfe/d (23,775 boe/d) in Q3 2010 to 218
MMcfe/d (36,390 boe/d) in Q3 2011, a 41% increase per share, a 53%
increase on an absolute basis, and a 46% increase in production per
share, debt adjusted (3).
-- Funds from operations ("FFO") in Q3 2011 increased 46% to $82.5 million
from $56.3 million in Q3 2010. The 8% year over year drop in realized
commodity prices from $5.83/Mcfe to $5.35/Mcfe was more than offset by
the increased production volumes and lower cash costs. FFO per share
were up 35% to $0.62/share.
-- Peyto's industry leading operating costs were $0.36/Mcfe ($2.14/boe), or
$0.49/Mcfe ($2.90/boe) including transportation, and were effectively
unchanged from Q3 2010. Total cash costs were 19% lower at $1.24/Mcfe,
resulting in a cash netback of $4.11/Mcfe ($24.64/boe), or an operating
margin(1) of 77%.
-- Capital expenditures of $111.6 million were invested in the quarter, up
75% from $63.7 million in Q3 2010. A total of 20 gross wells were
drilled during the period.
-- A 35% profit margin(2) or earnings of $37.7 million ($0.28/share) were
generated in the quarter and dividends of $24.0 million ($0.18/share)
were paid to shareholders, representing a payout ratio of 29% of FFO.
Third Quarter 2011 in Review
Peyto continued with its aggressive growth strategy in the third quarter,
investing into new lands, wells and infrastructure despite the persistently low
natural gas prices. This strategy is made possible due to Peyto's profitable,
low cost advantage which yields superior economic returns. As a result, a
production per share growth rate of 41% matched that of the previous quarter
despite wet weather and production disruptions resulting from new gas plant
startups. By the end of the third quarter almost 100 MMcfe/d (16,400 boe/d) of
new 2011 production had been built. Existing gas plants at Nosehill and Oldman
underwent expansion that will provide processing capacity for additional volumes
to be added during the 2011/2012 winter drilling season. Peyto's industry
leading cash costs were further reduced, strengthening netbacks, despite lower
realized hedging gains. Balance sheet strength was maintained with debt to
annualized FFO of 1.6 times, down from 2.0 times in Q3 2010, while additional
funding capacity was added by the recent expansion of Peyto's bank lines to $725
million. The strong financial and operating performance delivered in the quarter
resulted in an annualized 16% Return on Equity (ROE) and 13% Return on Capital
Employed (ROCE).
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 quarter divided by
revenue before royalties but including realized hedging gains/losses.
3. Per share results are adjusted for changes in net debt and equity. Net
debt is converted to equity using a Sept. 30 share price of $19.93 for
2011 and $15.54 for 2010. Natural gas volumes recorded in thousand cubic
feet (mcf) are converted to barrels of oil equivalent (boe) using the
ratio of six (6) thousand cubic feet to one (1) barrel of oil (bbl).
Natural gas liquids and oil volumes in barrel of oil (bbl) are converted
to thousand cubic feet equivalent (Mcfe) using a ratio of one (1) barrel
of oil to six (6) thousand cubic feet. This could be misleading,
particularily if used in isolation as it is based on an energy
equivalency conversion method primarily applied at the burner tip and
does not represent a value equivalency at the wellhead.
----------------------------------------------------------------------------
Three Months ended
September 30 %
2011 2010 Change
----------------------------------------------------------------------------
Operations
Production
Natural gas (mcf/d) 194,832 122,717 59%
Oil & NGLs (bbl/d) 3,918 3,322 18%
Thousand cubic feet equivalent (mcfe/d @
1:6) 218,338 142,651 53%
Barrels of oil equivalent (boe/d @ 6:1) 36,390 23,775 53%
Product prices
Natural gas ($/mcf) 4.43 5.16 (14)%
Oil & NGLs ($/bbl) 78.07 59.66 31%
Operating expenses ($/mcfe) 0.36 0.34 6%
Transportation ($/mcfe) 0.13 0.14 (7)%
Field netback ($/mcfe) 4.41 4.83 (9)%
General & administrative expenses
($/mcfe) 0.04 0.15 (73)%
Interest expense ($/mcfe) 0.26 0.39 (33)%
Financial ($000, except per share)
Revenue 107,526 76,450 41%
Royalties 9,265 6,800 36%
Funds from operations 82,506 56,341 46%
Funds from operations per share 0.62 0.46 35%
Total dividends 23,951 43,875 (45)%
Total dividends per share 0.18 0.36 (50)%
Payout ratio 29 78 (63)%
Earnings 37,741 33,983 11%
Earnings per diluted share 0.28 0.28 0%
Capital expenditures 111,570 63,721 75%
Weighted average common shares
outstanding 133,061,301 121,765,712 9%
As at September 30
Net debt (before future compensation expense and unrealized
hedging gains)
Shareholders' equity
Total assets
----------------------------------------------------------------------------
Nine Months ended
September 30 %
2011 2010 Change
----------------------------------------------------------------------------
Operations
Production
Natural gas (mcf/d) 181,881 113,093 61%
Oil & NGLs (bbl/d) 3,826 3,373 13%
Thousand cubic feet equivalent (mcfe/d @
1:6) 204,834 133,328 54%
Barrels of oil equivalent (boe/d @ 6:1) 34,139 22,221 54%
Product prices
Natural gas ($/mcf) 4.58 5.55 (17)%
Oil & NGLs ($/bbl) 79.45 64.70 23%
Operating expenses ($/mcfe) 0.35 0.37 (5)%
Transportation ($/mcfe) 0.13 0.13 -
Field netback ($/mcfe) 4.51 5.13 (12)%
General & administrative expenses
($/mcfe) 0.07 0.12 (42)%
Interest expense ($/mcfe) 0.26 0.40 (35)%
Financial ($000, except per share)
Revenue 310,297 230,794 34%
Royalties 31,195 25,693 21%
Funds from operations 234,212 167,755 40%
Funds from operations per share 1.76 1.41 25%
Total dividends 71,823 128,969 (44)%
Total dividends per share 0.54 1.08 (50)%
Payout ratio 31 77 (60)%
Earnings 102,147 104,995 (3)%
Earnings per diluted share 0.77 0.88 (13)%
Capital expenditures 284,373 150,991 88%
Weighted average common shares
outstanding 132,954,410 118,803,946 12%
As at September 30
Net debt (before future compensation
expense and unrealized hedging gains) 526,743 456,421 15%
Shareholders' equity 873,588 629,373 39%
Total assets 1,665,978 1,391,708 20%
----------------------------------------------------------------------------
Three Months ended Nine Months ended
September 30 September 30
($000) 2011 2010 2011 2010
----------------------------------------------------------------------------
Cash flows from operating activities 79,685 48,240 204,403 156,986
Change in non-cash working capital 1,807 3,649 22,224 2,420
Change in provision for performance
based compensation 1,014 4,452 7,585 8,349
----------------------------------------------------------------------------
Funds from operations 82,506 56,341 234,212 167,755
----------------------------------------------------------------------------
Funds from operations per share 0.62 0.46 1.76 1.41
----------------------------------------------------------------------------
(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 International Financial Reporting
Standards ("IFRS") and does not have a standardized meaning prescribed by IFRS.
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 IFRS. Funds from operations cannot be assured and
future dividends may vary.
Exploration & Development
During the quarter, Peyto further expanded its inventory of opportunities
through the evaluation and development of new zones and the acquisition of new
undeveloped lands.
Following the successful test of the first horizontal multi-stage frac Cardium
well in the Smoky area, Peyto acquired 15 sections of new land (9,600 acres net)
with 30 previously identified undeveloped horizontal locations. This is in
addition to the 15 locations already in inventory in this area. Many of these
locations will become part of Peyto's winter 2011/2012 drilling program.
The ongoing development of the Falher formation in the greater Sundance area is
yielding significant results for Peyto. Since the first horizontal test in the
summer of 2010, Peyto has now drilled 8 liquids rich Falher horizontal gas wells
(15-20 bbls/mmcf of NGLs), which combined, are currently producing 3,250 boe/d.
Internally developed drilling inventory in this formation alone has expanded to
over 180 locations based on this initial success. Profitable production from the
Falher is expected to become a greater part of Peyto's production mix in the
future.
In the third quarter, Peyto tested the Dunvegan formation in its Cutbank field
with horizontal multi-stage fracture technology. Initial test rates were
encouraging and an evaluation of production performance along with cost
optimization will determine how much more profitably this zone can be developed
with the new technology.
In anticipation of growing corporate production, significant investments in
infrastructure occurred in the third quarter as Peyto continued to build out
facility capacity. The Nosehill gas plant expansion was finalized with the
addition of three more compressors, a second inlet separator and a second
refrigeration plant that took processing capacity from 70 mmcf/d to 110 mmcf/d.
At the Oldman plant, compressor and refrigeration modifications added 17 mmcf/d
to the existing 110 mmcf/d of capacity, while a new pipeline installation
interconnected the two gathering systems for greater facility utilization and
production optimization. Peyto now has over 320 mmcf/d of inlet gas processing
capacity or the equivalent of 55,000 boe/d of owned and operated sales capacity.
Peyto's enhanced natural gas liquids recovery project at its Oldman gas plant
finished the final stages of engineering and has entered the procurement phase.
This project is scheduled for construction and startup in the fall of 2012 and
is expected to increase liquids recovery at Oldman by 15 bbls/mmcf from the
current 21 bbls/mmcf. As well, an evaluation of the potential for applying this
same concept to Peyto's other gas plants is now underway.
An increase in Peyto's targeted Deep Basin lands and the proving up of
additional prospects on existing lands means Peyto has a greater inventory of
drilling opportunities than ever in its history. As well, Peyto's operational
expertise and execution proficiency mean these opportunities will be developed
in a cost effective and timely manner, delivering greater returns.
Capital Expenditures
The third quarter was a very active period as Peyto invested $112 million into
all facets of the business. In total, 20 gross (17.4 net) wells were drilled, 23
gross (19.7 net) wells completed and 20 gross (16.2 net) wells brought on
production. Drilling, completion and wellsite connections accounted for $45.8
million, $25.5 million and $10.2 million, respectively. As well, $16.1 million
was invested into new facilities at the Nosehill and Oldman gas plants. Peyto
added to its more than 10 years of drilling inventory with 35 sections (22,400
net acres) of new undeveloped land containing over 50 identified drilling
locations. These new lands and additional seismic acquisitions accounted for $14
million in the quarter.
To the end of the third quarter of 2011, a total of 49 gross (42.9 net) wells
have been brought on stream accounting for 16,400 boe/d of new production at a
cumulative capital cost of $284 million. This results in a full cycle capital
efficiency of $17,300/boe/d. Not including the $79 million of facility, land and
seismic capital, half cycle capital efficiency of $12,500/boe/d was achieved.
Reduced drilling times and other operational efficiency gains have resulted in
capital efficiencies for 2011 that are virtually identical to those of 2009 and
2010. This is despite the 10-15% inflation in service cost rates driven by
rising oil prices over the last two years. Management believes Peyto's current
full cycle cost to build new production to be one of the lowest in Canada.
Financial Results
A realized natural gas price of $4.43/mcf and a liquids price of $78.07/bbl
combined for a net effective sales price of $5.35/Mcfe ($32.10/boe). Total cash
costs of $1.24/Mcfe ($7.46/boe) included royalties of $0.45/Mcfe, operating
costs of $0.36/Mcfe, transportation costs of $0.13/Mcfe, G&A expense of
$0.04/Mcfe, and interest expense of $0.26/Mcfe which resulted in a cash netback
of $4.11/Mcfe ($24.64/boe). Operating margin, or funds from operations divided
by revenue, was 77% in the third quarter, up from 74% a year ago.
Depletion, depreciation and accretion, now calculated using total proved plus
probable additional reserves and adjusted for future development capital, of
$1.55/Mcfe as well as a provision for deferred income tax and future market
based bonus of $0.68/Mcfe, reduced cash netbacks of $4.11/Mcfe to earnings of
$1.88/Mcfe. Profit margin, or earnings divided by revenue, was 35%, down from
45% in the previous year.
In conjunction with the fall review of its credit facility and a rebalancing of
the membership, Peyto's syndicate of lenders has increased the company's
borrowing capacity from $625 million to $725 million.
Marketing
Alberta daily natural gas prices averaged $3.47/GJ in the third quarter, up 3%
from the same period in 2010, while Edmonton light oil prices averaged $92/bbl,
a 24% increase from the $74/bbl in 2010. From these prices, Peyto realized an
unhedged natural gas price of $4.00/mcf and a blended oil and natural gas
liquids price of $78.07/bbl. These prices combined, with a realized gain from
forward sales of natural gas of $0.43/mcf, for the net effective sales price of
$5.35/Mcfe or $32.10/boe.
Peyto continued its practice of layering in future sales of natural gas,
although future prices are not much greater than those realized in the third
quarter. This practice is designed to smooth out the volatility in natural gas
prices and provide certainty for capital planning purposes and dividend
payments. As at September 30, 2011, Peyto had committed to the future sale of
35,820,000 gigajoules (GJ) of natural gas at an average price of $4.24 per GJ or
$4.96 per mcf based on Peyto's historical heat content premium. Had these
contracts been closed on September 30, 2011, Peyto would have realized a gain in
the amount of $19.3 million.
Activity Update
Peyto celebrated a milestone with the drilling of its 100th horizontal well in
late October 2011. Since the first well in August of 2009, Peyto has become an
industry leader deploying horizontal multi-stage frac technology to exploit its
Deep Basin tight gas resource plays. The continuous improvement in execution has
given the company a cost advantage over much of the industry and allowed Peyto
to offset recent service rate inflation with efficiency gains.
A high level of activity is expected to continue through the end of the year
with 5 to 6 drilling rigs active in Peyto's core areas. As of November 8, 2011,
production has exceeded 40,000 boe/d and is expected to grow to 42,000 boe/d by
year end resulting in another record year of production growth. For the balance
of the year, capital spending will be focused on drilling and connecting new
Cardium wells in the Kisku area, new Notikewin, Falher, and Bluesky wells in the
Greater Sundance area, and evaluating the Wilrich potential in three new Deep
Basin areas.
2012 Budget
The Board of Directors has approved a preliminary 2012 budget that includes a
capital program expected to range between $400 and $450 million. This program
has six horizontal drilling rigs active throughout the year in the ongoing core
area development of Peyto's many Deep Basin, liquids rich formations, as well as
exploratory work in several expansion areas. As usual, over 80% of the capital
will be directed to well-related costs including drilling, completion, wellsite
equipment and pipelines. The remainder of the capital will be directed to new
facility installations, facility expansions and the acquisition of new lands and
seismic.
Although 2011 is not yet finished, internal production forecasts suggest the
base production for 2012 will decline at an estimated 31%, less than the 34%
annual decline experienced in 2011. Assuming today's capital costs, it is
anticipated that full cycle capital efficiency for 2012, or the all-in cost to
build new production, will remain between $17,000/boe/d and $18,000/boe/d, a
level that has been achieved for the past three years. Using these capital
efficiency and decline assumptions, production for 2012 is forecast to exit
between 51,000 and 55,000 boe/d.
Growth Strategy
The continued growth anticipated for 2012 fits with Peyto's strategy of
maximizing returns. The company's low, full cycle development costs and low
producing costs are the foundation for these returns and provide robust
economics through a spectrum of natural gas prices. Based on current gas prices,
the capital investments over the last two years are yielding full cycle internal
rates of return in excess of 30%. Management believes that if this current low
gas price environment persists, Peyto's low cost advantage should enable the
company to continue delivering profitable growth. As always, Peyto plans to
maintain its financial flexibility with a healthy balance sheet.
Outlook
With a large and expanding inventory of undeveloped opportunities, a successful
track record of profitable growth and increased funding capacity, management
believes Peyto is well positioned to continue to deliver growth in production,
reserves and cashflow on a per share basis throughout 2012 and beyond.
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.
Conference Call and Webcast
A conference call will be held with the senior management of Peyto to answer
questions with respect to the 2011 third quarter on Thursday, November 10th,
2011, at 9:00 a.m. Mountain Standard Time (MST), or 11:00 a.m. Eastern Standard
Time (EST). To participate, please call 1-416-695-7848 (Toronto area) or
1-800-952-6845 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 5210084. The replay will be available at
11:00 a.m. MST, 1:00 p.m. EST Thursday, November 10th, 2011 until midnight EST
on Thursday, November 17th, 2011. The conference call can also be accessed
through the internet at
http://events.digitalmedia.telus.com/peyto/111011/index.php. After this time the
conference call will be archived on the Peyto Exploration & Development website
at www.peyto.com.
Management's Discussion and Analysis
Management's Discussion and Analysis of this third quarter report is available
on the Peyto website at http://www.peyto.com/news/Q32011MDandA.pdf. A complete
copy of the third quarter report to shareholders, including the Management's
Discussion and Analysis, and Financial Statements is also available at
www.peyto.com and will be filed at SEDAR, www.sedar.com, at a later date.
Darren Gee, President and CEO
Certain information set forth in this document and Management's Discussion and
Analysis, including management's assessment of Peyto's future plans and
operations, capital expenditures and capital efficiencies, 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
there from. In addition, Peyto is providing future oriented financial
information set out in this press release for the purposes of providing clarity
with respect to Peyto's strategic direction and readers are cautioned that this
information may not be appropriate for any other purpose. Other than is required
pursuant to applicable securities law, Peyto does not undertake to update
forward looking statements at any particular time.
Peyto Exploration & Development Corp.
Condensed Balance Sheet (unaudited)
(Amount in $ thousands)
September 30 December 31 January 1
2011 2010 2010
----------------------------------------------------------------------------
Assets
Current assets
Cash 9,632 7,894 -
Accounts receivable (Note 3) 56,170 55,876 58,305
Due from private placement (Note 7) - 12,423 2,728
Financial derivative instruments 19,347 25,247 8,683
(Note 12)
Prepaid expenses 3,763 3,280 3,786
----------------------------------------------------------------------------
88,912 104,720 73,502
----------------------------------------------------------------------------
Financial derivative instruments - 2,664 1,254
(Note 12)
Prepaid capital 4,379 - 955
Property, plant and equipment, net 1,572,687 1,367,869 1,178,402
(Note 4)
----------------------------------------------------------------------------
1,577,066 1,370,533 1,180,611
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1,665,978 1,475,253 1,254,113
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable and accrued 97,506 113,592 55,890
liabilities
Dividends payable (Note 7) 7,984 15,825 13,790
Provision for future performance 10,728 5,340 3,395
based compensation (Note 11)
----------------------------------------------------------------------------
116,218 134,757 73,075
----------------------------------------------------------------------------
Long-term debt (Note 5) 490,000 355,000 435,000
Provision for future performance 3,566 1,369 1,016
based compensation (Note 11)
Financial derivative instruments 15 - -
(Note 12)
Decommissioning provision (Note 6) 36,637 24,734 17,479
Deferred income taxes 145,954 114,610 191,907
----------------------------------------------------------------------------
676,172 495,713 645,402
----------------------------------------------------------------------------
Shareholders' or Unitholders' equity
Shareholders' capital (Note 7) 777,768 755,831 -
Unitholders' capital (Note 7) - - 501,219
Shares or Units to be issued (Note 7) - 17,285 2,728
Retained earnings 81,098 50,774 25,627
Accumulated other comprehensive 14,722 20,893 6,062
income (Note 7)
----------------------------------------------------------------------------
873,588 844,783 535,636
----------------------------------------------------------------------------
1,665,978 1,475,253 1,254,113
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Approved by the Board of Directors
Michael MacBean, Director
Darren Gee, Director
Peyto Exploration & Development Corp.
Condensed Income Statement (unaudited)
(Amount in $ thousands)
Three months ended Nine months ended
September 30 September 30
2011 2010 2011 2010
----------------------------------------------------------------------------
Revenue
Oil and gas sales 99,829 63,578 282,893 200,669
Realized gain on hedges
(Note 12) 7,697 12,872 27,404 30,124
Royalties (9,265) (6,800) (31,195) (25,693)
----------------------------------------------------------------------------
Petroleum and natural gas
sales, net 98,261 69,650 279,102 205,100
----------------------------------------------------------------------------
Expenses
Operating (Note 8) 7,157 4,462 19,672 13,634
Transportation 2,552 1,785 7,087 4,798
General and
administrative (Note 9) 841 1,925 3,795 4,395
Future performance based
compensation (Note 11) 1,014 4,452 7,585 8,349
Interest (Note 10) 5,205 5,137 14,336 14,518
Accretion of
decommissioning
liability (Note 10) 192 159 658 505
Depletion and
depreciation (Note 4) 30,987 19,862 90,863 56,836
Gains on divestitures - - (818) -
----------------------------------------------------------------------------
47,948 37,782 143,178 103,035
----------------------------------------------------------------------------
Earnings before taxes 50,313 31,868 135,924 102,065
----------------------------------------------------------------------------
Taxes
Deferred income tax
expense (recovery) 12,572 (2,115) 33,777 (2,930)
----------------------------------------------------------------------------
Earnings for the period 37,741 33,983 102,147 104,995
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Earnings per share or
unit (Note 7)
Basic and diluted $ 0.28 $ 0.28 $ 0.77 $ 0.88
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted average number
of common shares
outstanding (Note 7)
Basic and diluted 133,061,301 121,765,712 132,954,410 118,803,946
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Peyto Exploration & Development Corp.
Condensed Statement of Comprehensive Income (unaudited)
(Amount in $ thousands)
Three months ended Nine months ended
September 30 September 30
2011 2010 2011 2010
----------------------------------------------------------------------------
Earnings for the period 37,741 33,983 102,147 104,995
Other comprehensive income
Change in unrealized gain (loss) on
cash flow hedges 8,291 18,453 21,233 49,726
(net of deferred tax;
2011 - $0.1 million expense and $2.4
million recovery
(2010 - $0.3 million recovery and
$5.0 million expense))
Realized (gain) loss on cash flow
hedges (7,697) (12,872) (27,404) (30,124)
----------------------------------------------------------------------------
Comprehensive Income 38,335 39,564 95,976 124,597
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Peyto Exploration & Development Corp.
Condensed Statement of Changes in Equity (unaudited)
(Amount in $ thousands)
Nine months ended
September 30
2011 2010
----------------------------------------------------------------------------
Shareholders' / Unitholders' capital, Beginning of Year 755,831 501,219
----------------------------------------------------------------------------
Trust units issued - 74,863
Common shares / trust units issued by private placement 17,150 2,728
Common shares / trust units issuance costs (net of tax) (75) (2,421)
Common shares / trust units issued pursuant to DRIP 1,973 6,250
Common shares / trust units issued pursuant to OTUPP 2,889 13,352
----------------------------------------------------------------------------
Shareholders' / Unitholders' capital, End of Period 777,768 595,991
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Common shares / trust units to be issued, Beginning of 17,285 2,728
Year
----------------------------------------------------------------------------
Common shares / trust units issued (17,285) (2,728)
Trust units to be issued - 6,064
----------------------------------------------------------------------------
Common shares / trust units to be issued, End of Period - 6,064
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Retained earnings, Beginning of Year 50,774 25,627
----------------------------------------------------------------------------
Earnings for the period 102,147 104,995
Dividends (Note 7) (71,823) (128,968)
----------------------------------------------------------------------------
Retained earnings, End of Period 81,098 1,654
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated other comprehensive income, Beginning of 20,893 6,062
Year
----------------------------------------------------------------------------
Other comprehensive income (loss) (6,171) 19,602
----------------------------------------------------------------------------
Accumulated other comprehensive income, End of Period 14,722 25,664
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Shareholders' Equity 873,588 629,373
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Peyto Exploration & Development Corp.
Condensed Statement of Cash Flows (unaudited)
(Amount in $ thousands)
Three months ended Nine months ended
September 30 September 30
2011 2010 2011 2010
----------------------------------------------------------------------------
Cash provided by (used in)
Operating Activities
Earnings 37,741 33,983 102,147 104,995
Items not requiring cash:
Deferred income tax 12,572 (2,115) 33,777 (2,930)
Depletion and depreciation 30,987 19,862 90,863 56,836
Gain on disposition of assets - - (818) -
Accretion of decommissioning 192 159 658 505
liability
Change in non-cash working (1,807) (3,649) (22,224) (2,420)
capital related to operating
activities (Note 15)
----------------------------------------------------------------------------
79,685 48,240 204,403 156,986
----------------------------------------------------------------------------
Financing Activities
Issuance of common shares - 11,245 4,727 93,396
Issuance costs - - (99) (3,968)
Dividends declared (23,951) (40,609) (71,823) (121,836)
Increase (decrease) in bank debt 35,000 25,000 135,000 20,000
Change in non-cash working - 771 4,582 3,594
capital related to financing
activities (Note 15)
----------------------------------------------------------------------------
11,049 (3,593) 72,387 (8,814)
----------------------------------------------------------------------------
Investing Activities
Additions to property, plant and (111,289) (67,081) (287,997) (153,445)
equipment
Change in non-cash working 17,838 19,786 12,945 11,901
capital related to investing
activities (Note 15)
----------------------------------------------------------------------------
(93,451) (47,295) (275,052) (141,544)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net increase in cash (2,717) (2,648) 1,738 6,628
Cash, beginning of year 12,349 9,276 7,894 -
----------------------------------------------------------------------------
Cash, end of period 9,632 6,628 9,632 6,628
----------------------------------------------------------------------------
The following amounts are included in Cash Flows From Operating Activities:
----------------------------------------------------------------------------
Cash interest paid 5,205 5,137 14,336 14,518
Cash taxes paid - - - -
----------------------------------------------------------------------------
Peyto Exploration & Development Corp.
Notes to Condensed Financial Statements (unaudited)
As at September 30, 2011 and 2010
(Amount in $ thousands, except as otherwise noted)
1. Nature of operations
Peyto Exploration & Development Corp. ("Peyto" or the "Company") is a Calgary
based oil and natural gas company. The Company conducts exploration, development
and production activities in Canada. Peyto is incorporated and domiciled in the
Province of Alberta, Canada. The address of its registered office is 1500, 250 -
2nd Street SW, Calgary, Alberta, Canada, T2P 0C1.
On December 31, 2010, Peyto completed the conversion from an income trust to a
corporation pursuant to an arrangement under the Business Corporations Act
(Alberta); the ("2010 Arrangement"). As a result of this conversion, trust units
of Peyto Energy Trust (the "Trust") were exchanged for common shares of Peyto on
a one-for-one basis (see Note 7).
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.
There were no changes in Peyto's underlying operations associated with the 2010
Arrangement. The condensed financial statements and related financial
information have been prepared on a continuity of interest basis, which
recognizes Peyto as the successor entity and accordingly all comparative
information presented for the preconversion period is that of the Trust. For the
convenience of the reader, when discussing prior periods, the condensed
financial statements refer to common shares, shareholders and dividends although
for the pre-conversion period such items were trust units, unitholders' and
distributions, respectively.
Following the completion of the 2010 Arrangement, Peyto does not have any
subsidiaries.
These condensed financial statements were approved and authorized for issuance
by the Audit Committee of the Board of Directors of Peyto on November 8, 2011.
2. Basis of presentation
These unaudited condensed financial statements ("financial statements") for the
three and nine months ended September 30, 2011 have been prepared in accordance
with International Accounting Standard ("IAS") 34 Interim Financial Reporting.
These condensed interim financial statements do not include all of the
information required for annual financial statements. Amounts relating to the
three and nine months ended September 30, 2010 and as at December 31, 2010 were
previously presented in accordance with Canadian generally accepted accounting
principles ("Canadian GAAP"). These amounts have been restated as necessary to
be compliant with our accounting policies under International Financial
Reporting Standards ("IFRS"), which are included below. Reconciliations and
descriptions relating to the transition from Canadian GAAP to IFRS are included
in Note 17.
a) Summary of significant accounting policies
The precise determination of many assets and liabilities is dependent upon
future events and the preparation of periodic financial statements necessarily
involves the use of estimates and approximations. Accordingly, actual results
could differ from those estimates. The financial statements have, in
management's opinion, been properly prepared within reasonable limits of
materiality and within the framework of the Company's basis of presentation as
disclosed.
The following significant accounting policies have been adopted in the
preparation and presentation of the financial report:
b) Significant accounting estimates and judgements
The timely preparation of the unaudited condensed financial statements in
conformity with International Financial Reporting Standards ("IFRS") 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 unaudited condensed 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
condensed financial statements. Accordingly, actual results may differ from
estimated amounts as future confirming events occur.
Amounts recorded for depreciation, depletion and amortization, decommissioning
costs and obligations and amounts used for 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 condensed 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.
c) Presentation currency
All amounts in these financial statements are expressed in Canadian dollars, as
this is the functional and presentation currency of the Company.
d) Jointly controlled assets
A jointly controlled asset involves joint control and offers joint ownership by
the Company and other partners of assets contributed to or acquired for the
purpose of the jointly controlled assets, without the formation of a
corporation, partnership or other entity.
The Company accounts for its share of the jointly controlled assets, any
liabilities it has incurred, its share of any liabilities jointly incurred with
its partners, income from the sale or use of its share of the joint venture's
output, together with its share of the expenses incurred by the jointly
controlled asset and any expenses it incurs in relation to its interest in the
jointly controlled asset.
e) Exploration and evaluation assets
Pre-license costs
Costs incurred prior to obtaining the legal right to explore for hydrocarbon
resources are expensed in the period in which they are incurred. The Company has
no pre-license costs.
Exploration and evaluation costs
Once the legal right to explore has been acquired, costs directly associated
with an exploration well are capitalized as exploration and evaluation
intangible assets until the drilling of the well is complete and the results
have been evaluated. All such costs are subject to technical feasibility,
commercial viability and management review as well as review for impairment at
least once a year to confirm the continued intent to develop or otherwise
extract value from the discovery. The Company has no exploration or evaluation
costs.
f) Property, plant and equipment
Oil and gas properties and other property, plant and equipment is stated at
cost, less accumulated depreciation and accumulated impairment losses.
The initial cost of an asset comprises its purchase price or construction cost,
any costs directly attributable to bringing the asset into operation, the
initial estimate of the decommissioning provision and borrowing costs for
qualifying assets. The purchase price or construction cost is the aggregate
amount paid and the fair value of any other consideration given to acquire the
asset. Costs include expenditures on the construction, installation or
completion of infrastructure such well sites, pipelines and facilities including
activities such as drilling, completion and tie-in costs, equipment and
installation costs, associated geological and human resource costs, including
unsuccessful development or delineation wells.
Oil and natural gas asset swaps
For exchanges or parts of exchanges that involve assets, the exchange is
accounted for at fair value. Assets are then de-recognized at their current
carrying value.
Depletion and Depreciation
Oil and natural gas properties are depleted on a unit-of-production basis over
the proved plus probable reserves. All costs related to oil and natural gas
properties (net of salvage value) and estimated costs of future development of
proved plus probable undeveloped reserves are depleted and depreciated using the
unit-of-production method based on estimated gross proved plus probable 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.
Other property, plant and equipment are depreciated using a declining balance
method over remaining useful life.
g) Corporate Assets
Corporate assets not related to oil and natural gas exploration and development
activities are recorded at historical costs and depreciated over their useful
life. These assets are not significant or material in nature.
h) Impairment of non-financial assets
The Company assesses at each reporting date whether there is an indication that
an asset may be impaired. If any indication exists, or when annual impairment
testing for an asset is required, the Company estimates the asset's recoverable
amount. An asset's recoverable amount is the higher of fair value less costs to
sell or value-in-use and is determined for an individual asset, unless the asset
does not generate cash inflows that are largely independent of those from other
assets or groups of assets, in which case the recoverable amount is assessed as
part of a cash generating unit ("CGU"). If the carrying amount of an asset or
CGU exceeds its recoverable amount, the CGU is considered impaired and is
written down to its recoverable amount. In assessing value-in-use, the estimated
future cash flows are discounted to their present value using a pre-tax discount
rate that reflects current market assessments of the time value of money and the
risks specific to the asset. In determining fair value less costs to sell,
recent market transactions are taken into account, if available. If no such
transactions can be identified, an appropriate valuation model is used. These
calculations are corroborated by valuation multiples, quoted share prices for
publicly traded subsidiaries or other available fair value indicators.
Impairment losses of continuing operations are recognized in the income statement.
An assessment is made at each reporting date as to whether there is any
indication that previously recognized impairment losses may no longer exist or
may have decreased. If such indication exists, the Company estimates the asset's
or cash-generating unit's recoverable amount. A previously recognized impairment
loss is reversed only if there has been a change in the assumptions used to
determine the asset's recoverable amount since the last impairment loss was
recognized. The reversal is limited so that the carrying amount of the asset
does not exceed its recoverable amount, nor exceed the carrying amount that
would have been determined, net of depreciation, had no impairment loss been
recognized for the asset in prior years.
i) Leases
Leases or other arrangements entered into for the use of an asset are classified
as either finance or operating leases. Finance leases transfer to the Company
substantially all of the risks and benefits incidental to ownership of the
leased asset. Assets under finance lease are amortized over the shorter of the
estimated useful life of the assets and the lease term. All other leases are
classified as operating leases and the payments are amortized on a straight-line
basis over the lease term.
j) Financial instruments
Financial instruments within the scope of IAS 39 Financial Instruments:
Recognition and Measurement ("IAS 39") are initially recognized at fair value on
the condensed balance sheet. The Company has classified each financial
instrument into the following categories: "fair value through profit or loss";
"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 Fair value through profit or loss
----------------------------------------------------------------------------
Accounts Receivable Loans & receivables
----------------------------------------------------------------------------
Due from Private Placement Loans & receivables
----------------------------------------------------------------------------
Accounts Payable and Accrued Liabilities Other Liabilities
----------------------------------------------------------------------------
Provision for Future Performance Based Other Liabilities
Compensation
----------------------------------------------------------------------------
Dividends Payable Other Liabilities
----------------------------------------------------------------------------
Long Term Debt Other Liabilities
----------------------------------------------------------------------------
Financial Derivative Instruments Fair value through profit or loss
----------------------------------------------------------------------------
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 condensed income statement, 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.
Normal purchase or sale exemption
Contracts that were entered into and continue to be held for the purpose of the
receipt or delivery of a non-financial item in accordance with the Company's
expected purchase, sale or usage requirements fall within the exemption from IAS
32 Financial Instruments: Presentation ("IAS 32") and IAS 39, which is known as
the 'normal purchase or sale exemption'. The Company recognizes such contracts
in its balance sheet only when one of the parties meets its obligation under the
contract to deliver either cash or a non-financial asset.
k) Hedging
The Company uses derivative financial instruments from time to time to hedge its
exposure to commodity price fluctuations. 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 oil and natural gas revenue and cash flows in the same period
in which the revenues associated with the hedged transaction are recognized. 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.
l) Inventories
Inventories are stated at the lower of cost and net realizable value. Cost of
producing oil and natural gas is accounted on a weighted average basis. This
cost includes all costs incurred in the normal course of business in bringing
each product to its present location and condition.
m) Provisions
General
Provisions are recognized when the Company has a present obligation (legal or
constructive) as a result of a past event, it is probable that an outflow of
resources embodying economic benefits will be required to settle the obligation
and a reliable estimate can be made of the amount of the obligation. Where the
Company expects some or all of a provision to be reimbursed, the reimbursement
is recognized as a separate asset but only when the reimbursement is virtually
certain. The expense relating to any provision is presented in the income
statement net of any reimbursement. If the effect of the time value of money is
material, provisions are discounted using a current pre-tax rate that reflects,
where appropriate, the risks specific to the liability. Where discounting is
used, the increase in the provision due to the passage of time is recognized as
a finance cost.
Decommissioning provision
Decommissioning provision is recognized when the Company has a present legal or
constructive obligation as a result of past events, and it is probable that an
outflow of resources will be required to settle the obligation, and a reliable
estimate of the amount of obligation can be made. A corresponding amount
equivalent to the provision is also recognized as part of the cost of the
related property, plant and equipment. The amount recognized is the estimated
cost of decommissioning, discounted to its present value using a risk-free rate.
Changes in the estimated timing of decommissioning or decommissioning cost
estimates are dealt with prospectively by recording an adjustment to the
provision, and a corresponding adjustment to property, plant and equipment. The
accretion of the discount on the decommissioning provision is included as a
finance cost.
n) Taxes
Current income tax
Current income tax assets and liabilities for the current and prior periods are
measured at the amount expected to be recovered from or paid to the taxation
authorities. The tax rates and tax laws used to compute the amount are those
that are enacted or substantively enacted, at the reporting date, in Canada.
Current income tax relating to items recognized directly in equity is recognized
in equity and not in the income statement. Management periodically evaluates
positions taken in the tax returns with respect to situations in which
applicable tax regulations are subject to interpretation and establishes
provisions where appropriate.
Deferred tax
The Company follows the liability method of accounting for income taxes. Under
this method, income tax assets and liabilities are recognized for the estimated
tax consequences attributable to differences between the amounts reported in the
financial statements and their respective tax bases, using enacted or
substantively enacted tax rates expected to apply when the asset is realized or
the liability settled. Deferred tax assets are only recognized to the extent it
is probable that sufficient future taxable income will be available to allow the
future income tax asset to be realized. Accumulated deferred 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, except for items recognized in shareholders' equity.
o) Revenue recognition
Revenue from the sale of oil, natural gas and natural gas liquids is recognized
when the significant risks and rewards of ownership have been transferred, which
is when title passes to the purchaser. This generally occurs when product is
physically transferred into a pipe or other delivery system.
Gains and Losses on Disposition
For all dispositions, either through sale or exchange, gains and losses are
calculated as the difference between the sale or exchange value in the
transaction and the carrying value of the disposed assets disposed. Gains and
losses on disposition are recognized in earnings in the same period as the
transaction date.
p) Borrowing costs
Borrowing costs directly relating to the acquisition, construction or production
of a qualifying capital project under construction are capitalized and added to
the project cost during construction until such time the assets are
substantially ready for their intended use, which is, when they are capable of
commercial production. Where the funds used to finance a project form part of
general borrowings, the amount capitalized is calculated using a weighted
average of rates applicable to relevant general borrowings of the Company during
the period. All other borrowing costs are recognized in the income statement in
the period in which they are incurred.
q) Share-based payments
Liability-settled share-based payments to employees are measured at the fair
value of the liability award at the grant date. A liability equal to fair value
of the payments is accrued over the vesting period measured at fair value using
the Black-Scholes option pricing model.
The fair value determined at the grant date of the liability-settled share-based
payments is expensed on a graded basis over the vesting period, based on the
Company's estimate of liability instruments that will eventually vest. At the
end of each reporting period, the Company revises its estimate of the number of
liability instruments expected to vest. The impact of the revision of the
original estimates, if any, is recognized in the income statement such that the
cumulative expense reflects the revised estimate, with a corresponding
adjustment to related liability on the balance sheet.
r) Earnings per share
Basic and diluted earnings per share is computed by dividing the net earnings
available to common shareholders by the weighted average number of shares
outstanding during the reporting period. The Company has no dilutive instrument
outstanding which would cause a difference between the basic and diluted
earnings per share.
s) Share capital
Common shares are classified within shareholders' equity. Incremental costs
directly attributable to the issuance of shares are recognized as a deduction
from shareholders' capital.
t) Standards issued but not yet effective
Presentation of Financial Statements
As of January 1, 2012, the Company will be required to adopt IAS 1,
"Presentation of Items of OCI: Amendments to IAS 1 Presentation of Financial
Statements." The amendments stipulate the presentation of net earnings and OCI
and also require the Company to group items within OCI based on whether the
items may be subsequently reclassified to profit or loss. The adoption of the
amendments to this standard is not expected to have a material impact on the
Company's financial position or results.
Financial Instruments
As of January 1, 2013, the Company will be required to adopt IFRS 9 "Financial
Instruments" which covers the classification and measurement of financial assets
as part of its project to replace IAS 39 "Financial Instruments: Recognition and
Measurement." This standard replaces the current models for financial assets and
liabilities with a single model. Under this guidance, entities have the option
to recognize financial liabilities at fair value through profit or loss. If this
option is elected, entities would be required to reverse the portion of the fair
value change due to its own credit risk out of profit or loss and recognize the
change in other comprehensive income. The implementation of the issued standard
is not expected to have a material impact on the Company's financial position or
results.
Consolidated Financial Statements
As of January 1, 2013, the Company will be required to adopt IFRS 10,
"Consolidated Financial Statements," which provides a single control model to be
applied in the assessment of control for all entities in which the Company has
an investment, including special purpose entities currently in the scope of
Standing Interpretations Committee ("SIC") 12. Under the new control model, the
Company has control over an investment if the Company has the ability to direct
the activities of the investment, is exposed to the variability of returns from
the investment and there is a linkage between the ability to direct activities
and the variability of returns. The Company does not expect IFRS 10 to have a
material impact on its financial position or results.
Joint Arrangements
As of January 1, 2013, the Company will be required to adopt IFRS 11, "Joint
Arrangements," which specifies that joint arrangements are classified as either
joint operations or joint ventures. Parties to a joint operation retain the
rights and obligations to individual assets and liabilities of the operation,
while parties to a joint venture have rights to the net assets of the venture.
Any arrangement which is not structured through a separate entity or is
structured through a separate entity but such separation is ineffective such
that the parties to the arrangement have rights to the assets and obligations
for the liabilities will be classified as a joint operation. Joint operations
shall be accounted for in a manner consistent with jointly controlled assets and
operations whereby the Company's contractual share of the arrangement's assets,
liabilities, revenues and expenses are included in the consolidated financial
statements. Any arrangement structured through a separate vehicle that does
effectively result in separation between the Company and the arrangement shall
be classified as a joint venture and accounted for using the equity method of
accounting. Under the existing IFRS standard, the Company has the option to
account for any interests it has in joint ventures using proportionate
consolidation or equity accounting. The Company does not expect IFRS 11 to have
a material impact on its financial position or results.
Disclosure of Interests in Other Entities
As of January 1, 2013, the Company will be required to adopt IFRS 12,
"Disclosure of Interests in Other Entities," which contains new disclosure
requirements for interests the Company has in subsidiaries, joint arrangements,
associates and unconsolidated structured entities. Required disclosures aim to
provide readers of the financial statements with information to evaluate the
nature of and risks associated with the Company's interests in other entities
and the effects of those interests on the Company's financial statements. The
Company intends to adopt IFRS 12 in its financial statements for the annual
period beginning on January 1, 2013. The Company does not expect IFRS 12 to have
a material impact on its financial position or results.
Investments in Associates and Joint Ventures
As of January 1, 2013, the Company will be required to adopt amendments to IAS
28, "Investments in Associates and Joint Ventures," which provide additional
guidance applicable to accounting for interests in joint ventures or associates
when a portion of an interest is classified as held for sale or when the Company
ceases to have joint control or significant influence over an associate or joint
venture. When joint control or significant influence over an associate or joint
venture ceases, the Company will no longer be required to re-measure the
investment at that date. When a portion of an interest in a joint venture or
associate is classified as held for sale, the portion not classified as held for
sale shall be accounted for using the equity method of accounting until the sale
is completed at which time the interest is reassessed for prospective accounting
treatment. The Company does not expect the amendments to IAS 28 to have a
material impact on the financial position or results.
Fair Value Measurement
As of January 1, 2013, the Company will be required to adopt IFRS 13, "Fair
Value Measurement," which replaces fair value measurement guidance contained in
individual IFRSs, providing a single source of fair value measurement guidance.
The standard provides a framework for measuring fair value and establishes new
disclosure requirements to enable readers to assess the methods and inputs used
to develop fair value measurements and for recurring valuations that are subject
to measurement uncertainty, the effect of those measurements on the financial
statements. The Company intends to adopt IFRS 13 prospectively in its financial
statements for the annual period beginning on January 1, 2013. The extent of the
impact of adoption of IFRS 13 has not yet been determined.
Employee Benefits
As of January 1, 2013, the Company will be required to adopt IAS 19, "Employee
Benefits" which eliminates the corridor method that permits the deferral of
actuarial gains and losses, to revise the presentation requirements for changes
in defined benefit plan assets and liabilities and to enhance the required
disclosures for defined benefit plans. The Company does not expect the
amendments to IAS 19 to have a material impact on the financial position or
results.
3. Accounts receivable
September 30 December 31 January 1
2011 2010 2010
----------------------------------------------------------------------------
Accounts receivable - general 49,015 48,721 51,150
Accounts receivable - tax 7,155 7,155 7,155
----------------------------------------------------------------------------
56,170 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.
4. Property, plant and equipment, net
Processing
Petroleum assets and Corporate
properties facilities assets Total
----------------------------------------------------------------------------
Cost
----------------------------------------------------------------------------
At January 1, 2010 1,112,677 65,353 1,007 1,179,037
----------------------------------------------------------------------------
Additions 255,374 19,607 - 274,981
Dispositions (1,094) - - (1,094)
----------------------------------------------------------------------------
At December 31, 2010 1,366,957 84,960 1,007 1,452,924
----------------------------------------------------------------------------
Additions 256,268 40,049 - 296,317
Dispositions (698) - - (698)
----------------------------------------------------------------------------
At September 30, 2011 1,622,527 125,009 1,007 1,748,543
----------------------------------------------------------------------------
Accumulated Depreciation
----------------------------------------------------------------------------
At January 1, 2010 - - (635) (635)
----------------------------------------------------------------------------
Depletion and depreciation (80,496) (3,867) (89) (84,452)
Dispositions 32 - - 32
----------------------------------------------------------------------------
At December 31, 2010 (80,464) (3,867) (724) (85,055)
----------------------------------------------------------------------------
Depletion and depreciation (87,083) (3,728) (52) (90,863)
Dispositions 62 - - 62
----------------------------------------------------------------------------
At September 30, 2011 (167,485) (7,595) (776) (175,856)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net book value at
September 30, 2011 1,455,042 117,414 231 1,572,687
----------------------------------------------------------------------------
----------------------------------------------------------------------------
During the three and nine month period ended September 30, the Company
capitalized $1.7 million and $4.4 million (2010 - $0.6 and $2.8 million) of
general and administrative and share based payments directly attributable to
production and development activities.
The Company performs an impairment test calculation when indicators are present
which negatively affect the value of the Company's individual assets or its
total asset base. Assets which have indicators of impairment are then aggregated
to its cash-generating units at which point the measurement of impairment is
calculated.
The Company did not have any indicators of impairment in the current period.
5. Long-term debt
The Company has a syndicated $625 million extendible revolving credit facility
with a stated term date of April 29, 2012. 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 cash flow ratio that range
from prime to prime plus 1.25% to 2.75% for debt to earnings before interest,
taxes, depreciation, depletion and amortization (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.
Total cash interest expense for the three months ended was $5.2 million (2010 -
$5.1 million) and the average borrowing rate for the period was 4.4% (2010 -
4.8%). Total cash interest expense for the nine months ended was $14.3 million
(2010 - $14.5 million) and the average borrowing rate for the period was 4.4%
(2010 - 4.6%).
On October 28, 2011, an amendment to the Company's credit agreement was signed
increasing the credit facilities to $725 million with a stated term date of
April 29, 2012. The facility is made up of a $30 million working capital
sub-tranche and a $695 million production line.
6. Decommissioning provision
The Company makes provision for the future cost of decommissioning wells,
pipelines and facilities on a discounted basis based on the commissioning of
these assets.
The decommissioning provision represents the present value of the
decommissioning costs related to the above infrastructure, which are expected to
be incurred over the economic life of the assets. The provisions have been based
on the Company's internal estimates on the cost of decommissioning, the discount
rate, the inflation rate and the economic life of the infrastructure.
Assumptions, based on the current economic environment, have been made which
management believes are a reasonable basis upon which to estimate the future
liability. These estimates are reviewed regularly to take into account any
material changes to the assumptions. However, actual decommissioning costs will
ultimately depend upon the future market prices for the necessary
decommissioning work required which will reflect market conditions at the
relevant time. Furthermore, the timing of the decommissioning is likely to
depend on when production activities ceases to be economically viable. This in
turn will depend and be directly related to the current and future commodity
prices, which are inherently uncertain.
The following table reconciles the change in decommissioning liabilities:
----------------------------------------------------------------------------
Balance, December 31, 2010 (1) 24,734
----------------------------------------------------------------------------
New or increased provisions 3,656
Accretion of discount 658
Change in discount rate 7,589
----------------------------------------------------------------------------
Balance, September 30, 2011 (2) 36,637
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Current -
Non-current 36,637
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Based on a total future undiscounted liability of $86.1 million to be
incurred over the next 50 years at an inflation rate of 2% and a discount rate
of 3.54%.
(2) Based on a total future undiscounted liability of $97.9 million to be
incurred over the next 50 years at an inflation rate of 2% and a discount rate
of 2.77%.
7. Shareholders' capital and Unitholders' capital
Authorized: Unlimited number of voting common shares
Issued and Outstanding
Number of Amount
Common Shares and Units (no par value) Common Shares $
----------------------------------------------------------------------------
Balance, January 1, 2010 114,920,194 501,219
Trust units issued 13,880,500 218,704
Trust units issuance costs (net of tax) - (7,680)
Trust units issued by private placement 196,420 2,728
Trust units issued pursuant to DRIP 746,079 10,558
Trust units issued pursuant to OTUPP 2,132,189 30,302
Exchanged for common shares pursuant to the
Arrangement (Note 1) (131,875,382) (755,831)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance, December 31, 2010 131,875,382 755,831
Common shares issued by private placement 906,196 17,150
Common share issuance costs (net of tax) - (75)
Common shares issued pursuant to DRIP 113,527 1,973
Common shares issued pursuant to OTUPP 166,196 2,889
----------------------------------------------------------------------------
Balance, September 30, 2011 133,061,301 777,768
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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).
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 Distribution Reinvestment Plan ("DRIP") 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.
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.
On January 14, 2011, 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.
On March 25, 2011, Peyto completed a private placement of 250,615 common shares
to employees and consultants for net proceeds of $4.6 million ($18.86 per
share). Subsequent to the issuance of these shares, 133,061,301 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 for the three month and nine month period
ended of 133,061,301 and 132,954,410 (2010 - 121,765,712 and 118,803,946),
respectively. There are no dilutive instruments outstanding.
Dividends
During the three and nine months ended September 30, 2011, Peyto declared and
paid dividends of $0.18 and $0.54 per common share, respectively or $0.06 per
common share per month, totaling $24.0 million and $71.8 million (2010 - $0.36
and $1.08 per share, respectively or $0.12 per share per month, $43.9 million
and $129.0 million), respectively.
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 an equity category comprised of the cumulative amounts
of OCI.
Accumulated hedging gains
2011
----------------------------------------------------------------------------
Balance, January 1, 2011 20,893
Hedging gains (losses) (6,171)
----------------------------------------------------------------------------
Balance, September 30, 2011 14,722
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gains and losses from cash flow hedges are accumulated until settled. These
outstanding hedging contracts are recognized in earnings on settlement with
gains and losses being recognized as a component of net revenue. Further
information on these contracts is set out in Note 12.
8. Operating expenses
The Company's operating expenses include all costs with respect to day-to-day
well and facility operations. Processing and gathering recoveries related to
jointly controlled assets and third party natural gas reduces operating
expenses.
Three months ended Nine months ended
September 30 September 30
2011 2010 2011 2010
----------------------------------------------------------------------------
Field expenses 9,952 7,055 26,953 21,565
Processing and gathering recoveries (2,795) (2,593) (7,281) (7,931)
----------------------------------------------------------------------------
Total operating expenses 7,157 4,462 19,672 13,634
----------------------------------------------------------------------------
----------------------------------------------------------------------------
9. General and administrative expenses
General and administrative expenses are reduced by operating and capital
overhead recoveries from operated properties.
Three months ended Nine months ended
September 30 September 30
2011 2010 2011 2010
----------------------------------------------------------------------------
General and administrative expenses 2,538 2,507 8,238 7,244
Overhead recoveries (1,697) (582) (4,443) (2,849)
----------------------------------------------------------------------------
Net general and administrative
expenses 841 1,925 3,795 4,395
----------------------------------------------------------------------------
----------------------------------------------------------------------------
10. Finance costs
Three months ended Nine months ended
September 30 September 30
2011 2010 2011 2010
----------------------------------------------------------------------------
Cash interest expense 5,205 5,137 14,336 14,518
Accretion of discount on provisions 192 159 658 505
----------------------------------------------------------------------------
5,397 5,296 14,994 15,023
----------------------------------------------------------------------------
----------------------------------------------------------------------------
11. Future Performance based compensation
The Company awards performance based compensation to employees 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, distributions, 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%.
Market Based Component
Under the market based component, rights with a three year vesting period are
allocated to employees. 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 common share for that period.
The fair values were calculated using a Black-Scholes valuation model. The
principal inputs to the option valuation model were:
September 30 December 31
2011 2010
----------------------------------------------------------------------------
Share price $19.93 $18.49
Exercise price $9.57 - $19.10 $6.62 - $11.66
Expected volatility 25% - 31% 0% - 28%
Option life 0.25 - 2.25 years 1 - 2 years
Dividend yield 0% 0%
Risk-free interest rate 0.91% 1.66%
----------------------------------------------------------------------------
12. Financial instruments
Financial Instrument Classification and Measurement
Financial instruments of the Company carried on the 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 September 30, 2011.
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
September 30, 2011, the carrying value of cash and financial derivative
instruments are carried at fair value. Accounts receivable, due from private
placement, current liabilities 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
September 30, 2011 is as follows:
Fair
Notional Effective Value September December 31
Description (1) Term Rate Level 30, 2011 2010
----------------------------------------------------------------------------
Natural gas
financial
swaps - 2011-
AECO 35.82GJ (2) 2013 $4.24/GJ Level 1 19,332 27,911
----------------------------------------------------------------------------
(1) Notional values as at September 30, 2011 (2) Millions of gigajoules
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Natural Gas Price
Period Hedged Type Daily Volume (CAD)
----------------------------------------------------------------------------
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, 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 October 31, 2011 Fixed Price 5,000 GJ $3.80/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
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
April 1, 2011 to March 31, 2013 Fixed Price 5,000 GJ $3.80/GJ
April 1, 2011 to March 31, 2013 Fixed Price 5,000 GJ $4.055/GJ
May 1, 2011 to March 31, 2012 Fixed Price 5,000 GJ $4.00/GJ
June 1, 2011 to March 31, 2013 Fixed Price 5,000 GJ $4.17/GJ
June 1, 2011 to March 31, 2013 Fixed Price 5,000 GJ $4.10/GJ
June 1, 2011 to March 31, 2013 Fixed Price 5,000 GJ $4.10/GJ
July 1, 2011 to October 31, 2011 Fixed Price 5,000 GJ $4.03/GJ
November 1, 2011 to March 31, 2012 Fixed Price 5,000 GJ $4.50/GJ
November 1, 2011 to March 31, 2013 Fixed Price 5,000 GJ $4.00/GJ
April 1, 2012 to October 31, 2013 Fixed Price 5,000 GJ $4.00/GJ
April 1, 2012 to October 31, 2013 Fixed Price 5,000 GJ $4.00/GJ
----------------------------------------------------------------------------
As at September 30, 2011, the Company had committed to the future sale of
35,820,000 gigajoules (GJ) of natural gas at an average price of $4.24 per GJ or
$4.96 per mcf based on the historical heating value of Peyto's natural gas. Had
these contracts been closed on September 30, 2011, the Company would have
realized a gain in the amount of $19.3 million. If the AECO gas price on
September 30, 2011 were to increase by $1/GJ, the unrealized gain would decrease
by approximately $35.8 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 September 30, 2011 the Company entered into the following contracts:
----------------------------------------------------------------------------
Natural Gas Price
Period Hedged Type Daily Volume (CAD)
----------------------------------------------------------------------------
April 1, 2012 to October 31, 2013 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 three month and nine month period ended September 30, 2011
would decrease by $1.2 million and $3.3 million, respectively. 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 three months ended
September 30, 2011, approximately 51% was received from four companies (19%,
11%, 11% and 10%) (September 30, 2010 - 92%, six companies (20%, 19%, 18%, 13%,
12% and 10%)). Of the Company's revenue for the nine months ended September 30,
2011, approximately 66% was received from five companies (18%, 14%, 13%, 11% and
10%) (September 30, 2010 - 94% was received from six companies (23%, 19%, 16%,
13%, 12% and 11%)). Of the Company's accounts receivable at September 30, 2011,
approximately 11% was receivable from a single company (At December 31, 2010 -
13%, one company). The maximum exposure to credit risk is represented by the
carrying amount on the condensed 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 September 30, 2011, 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 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
September 30, 2011:
less than 1-2 2-5
1 Year Years Years Thereafter
----------------------------------------------------------------------------
Accounts payable and accrued
liabilities 97,506
Dividends payable 7,984
Provision for future market and
reserves based bonus 10,728 3,566
Financial derivative instrument 15
Long-term debt(1) 490,000
----------------------------------------------------------------------------
(1) Revolving credit facility renewed annually (see Note 7)
13. 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, adjust its
capital spending or change dividends paid to manage its current and projected
debt levels. The Company monitors capital based on the following non-IFRS
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.
September 30 December 31
2011 2010
----------------------------------------------------------------------------
Shareholders' equity 873,588 844,783
Long-term debt 490,000 355,000
Working capital deficit 27,306 30,037
----------------------------------------------------------------------------
1,390,894 1,229,820
----------------------------------------------------------------------------
----------------------------------------------------------------------------
14. Related party transactions
An officer and director of Peyto 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.
15. Supplemental cash flow information
Changes in non-cash working capital balances
Three months ended Nine months ended
September 30 September 30
2011 2010 2011 2010
----------------------------------------------------------------------------
(Increase)/decrease of assets:
Accounts receivable (3,690) (6,848) (295) 2,056
Due from private placement - - 12,423 2,728
Prepaid expenses 1,863 1,269 (483) (580)
Increase/(decrease) of liabilities:
Accounts payable and accrued
liabilities 16,844 17,265 (16,086) (344)
Dividends payable - 771 (7,841) 866
Provision for future performance
based compensation 1,014 4,451 7,585 8,349
----------------------------------------------------------------------------
16,031 16,908 (4,697) 13,075
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Attributable to operating
activities (1,807) (3,649) (22,224) (2,420)
Attributable to financing
activities - 771 4,582 3,594
Attributable to investing
activities 17,838 19,786 12,945 11,901
----------------------------------------------------------------------------
16,031 16,908 (4,697) 13,075
----------------------------------------------------------------------------
----------------------------------------------------------------------------
16. Commitments and contingencies
Following is a summary of the Company's commitment related to an operating lease
as at September 30, 2011.
2011 2012 2013 2014 2015 Thereafter
----------------------------------------------------------------------------
Operating lease 265 1,058 1,058 1,058 - -
----------------------------------------------------------------------------
Total 265 1,058 1,058 1,058 - -
----------------------------------------------------------------------------
The Company has no other contractual obligations or commitments as at September
30, 2011.
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 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.
17. Transition to IFRS
For all periods up to and including the year ended December 31, 2010, the
Company prepared its financial statements in accordance with Canadian GAAP. The
Company has prepared financial statements which comply with IFRS's applicable
for periods beginning on or after the transition date of January 1, 2010 and the
significant accounting policies meeting those requirements are described in Note
2.
The effect of the Company's transition to IFRS is summarized in this note as
follows:
(i) Transition elections
(ii) Reconciliation of the Balance Sheets, Income Statements and Comprehensive
Income as previously reported under Canadian GAAP to IFRS
(iii) IFRS adjustments
(i) Transition elections
IFRS 1 allows first-time adopters certain exemptions from the general
requirement to apply IFRS as effective for December 2011 year ends
retrospectively. The Company has taken the following exemptions:
(a) IFRS 3 Business Combinations has not been applied to acquisitions of
subsidiaries or of interests in associates and joint ventures that occurred
before January 1, 2010, the Company's date of transition.
(b) IFRS 2 Share-based Payment has not been applied to any equity instruments
that were granted on or before November 7, 2002, nor has it been applied to
equity instruments granted after November 7, 2002 that vested before January 1,
2009.
(c) The Company has elected under IFRS 1 First-time Adoption of IFRS to measure
oil and gas assets at the date of transition at a deemed cost under Canadian
GAAP.
(d) The Company has elected to apply the exemption from full retrospective
application of decommissioning provisions as allowed under IFRS 1 First Time
Adoption of IFRS. As such the Company has re-measured the provisions as at
January 1, 2010 under IAS 37 Provisions, Contingent Liabilities and Contingent
Assets, and estimated the amount to be included in the retained earnings on
transition to IFRS.
Effect of
(ii) IFRS Balance Sheet Notes Canadian Transition to
as at January 1, 2010 17(iii) GAAP IFRS IFRS
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Assets
Current assets
Accounts receivable 58,305 - 58,305
Due from private
placement 2,728 - 2,728
Financial derivative
instruments 8,683 - 8,683
Prepaid expenses 3,786 - 3,786
----------------------------------------------------------------------------
73,502 - 73,502
----------------------------------------------------------------------------
Prepaid capital 955 - 955
Financial derivative
instruments 1,254 - 1,254
Oil and gas assets 1,178,402 - 1,178,402
----------------------------------------------------------------------------
1,180,611 - 1,180,611
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1,254,113 - 1,254,113
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable and
accrued liabilities 55,890 - 55,890
Distributions payable 13,790 - 13,790
Provision for future
performance based
compensation (d) 2,001 1,394 3,395
----------------------------------------------------------------------------
71,681 1,394 73,075
----------------------------------------------------------------------------
Long-term debt 435,000 - 435,000
Provision for future
performance based
compensation (d) 1,041 (25) 1,016
Decommissioning
provision (c) 10,487 6,992 17,479
Deferred income taxes (e) 123,421 68,486 191,907
----------------------------------------------------------------------------
569,949 75,453 645,402
----------------------------------------------------------------------------
Unitholders' equity
Unitholders' capital (e) 500,407 812 501,219
Units to be issued 2,728 - 2,728
Retained earnings 99,749 (74,122) 25,627
Accumulated other
comprehensive income (e) 9,599 (3,537) 6,062
----------------------------------------------------------------------------
612,483 (76,847) 535,636
----------------------------------------------------------------------------
1,254,113 - 1,254,113
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Effect of
IFRS Balance Sheet as at Notes Canadian Transition to
September 30, 2010 17(iii) GAAP IFRS IFRS
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Assets
Current assets
Cash 6,628 - 6,628
Accounts receivable 56,249 - 56,249
Financial derivative
instruments 35,399 - 35,399
Inventory and prepaid
expenses 4,366 - 4,366
----------------------------------------------------------------------------
102,642 - 102,642
----------------------------------------------------------------------------
Financial derivative
instruments 6,115 - 6,115
Prepaid capital 3,362 - 3,362
Oil and gas assets (f) 1,265,816 13,773 1,279,589
----------------------------------------------------------------------------
1,275,293 13,773 1,289,066
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1,377,935 13,773 1,391,708
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable and
accrued liabilities 55,546 - 55,546
Distributions payable 14,656 - 14,656
Provision for future
performance based
compensation (d) 11,486 (1,538) 9,948
----------------------------------------------------------------------------
81,688 (1,538) 80,150
----------------------------------------------------------------------------
Long-term debt 455,000 - 455,000
Provision for future
performance based
compensation (d) 2,990 (178) 2,812
Decommissioning
provision (c) 11,449 13,518 24,967
Deferred income taxes (e) 127,232 72,174 199,406
----------------------------------------------------------------------------
596,671 85,514 682,185
----------------------------------------------------------------------------
Unitholders' equity
Unitholders' capital (e) 594,437 1,554 595,991
Units to be issued 6,064 - 6,064
Retained earnings 64,919 (63,265) 1,654
Accumulated other
comprehensive income (e) 34,156 (8,492) 25,664
----------------------------------------------------------------------------
699,576 (70,203) 629,373
----------------------------------------------------------------------------
1,377,935 13,773 1,391,708
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Effect of
IFRS Balance Sheet as at Notes Canadian Transition to
December 31, 2010 17(iii) GAAP IFRS IFRS
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Assets
Current assets
Cash 7,894 - 7,894
Accounts receivable 55,876 - 55,876
Due from private
placement 12,423 - 12,423
Financial derivative
instruments 25,247 - 25,247
Inventory and prepaid
expenses 3,280 - 3,280
----------------------------------------------------------------------------
104,720 - 104,720
----------------------------------------------------------------------------
Financial derivative
instruments 2,664 - 2,664
Oil and gas assets (f) 1,347,191 20,678 1,367,869
----------------------------------------------------------------------------
1,349,855 20,678 1,370,533
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1,454,575 20,678 1,475,253
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable and
accrued liabilities 113,592 - 113,592
Dividends payable 15,825 - 15,825
Provision for future
performance based
compensation (d) 5,567 (227) 5,340
----------------------------------------------------------------------------
134,984 (227) 134,757
----------------------------------------------------------------------------
Long-term debt 355,000 - 355,000
Provision for future
performance based
compensation (d) 1,452 (83) 1,369
Decommissioning
provision (c) 11,926 12,808 24,734
Deferred income taxes (e) 112,567 2,043 114,610
----------------------------------------------------------------------------
480,945 14,768 495,713
----------------------------------------------------------------------------
Shareholders' equity
Shareholders' capital (e) 754,493 1,338 755,831
Shares to be issued 17,285 - 17,285
Retained earnings 46,319 4,455 50,774
Accumulated other
comprehensive income (e) 20,549 344 20,893
----------------------------------------------------------------------------
838,646 6,137 844,783
----------------------------------------------------------------------------
1,454,575 20,678 1,475,253
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(ii) Reconciliation of
earnings and
comprehensive income
for the three months Effect of
ended September 30, Notes Canadian Transition to
2010 17(iii) GAAP IFRS IFRS
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue
Oil and gas sales 63,578 - 63,578
Realized gain on hedges 12,872 - 12,872
Royalties (6,800) - (6,800)
----------------------------------------------------------------------------
Petroleum and natural
gas sales, net 69,650 - 69,650
----------------------------------------------------------------------------
Expenses
Operating 4,462 - 4,462
Transportation 1,785 - 1,785
General and
administrative (f) 1,524 401 1,925
Future performance based
compensation (d) 2,933 1,519 4,452
Interest 5,137 - 5,137
Accretion of
decommissioning
liability (c) - 159 159
Depletion and
depreciation (f) 22,229 (2,367) 19,862
----------------------------------------------------------------------------
38,070 (288) 37,782
----------------------------------------------------------------------------
Earnings before taxes 31,580 288 31,868
----------------------------------------------------------------------------
Taxes
Deferred income tax
recovery (e) 987 1,128 2,115
----------------------------------------------------------------------------
Earnings for the period 32,567 1,416 33,983
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Other comprehensive
income (loss)
Change in unrealized
gain (loss) on cash
flow hedges (e) 18,104 349 18,453
Realized (gain) loss on
cash flow hedges (12,872) - (12,872)
----------------------------------------------------------------------------
Comprehensive income for
the period 37,799 1,765 39,564
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(ii) Reconciliation of
earnings and
comprehensive income
for the nine months Effect of
ended September 30, Notes Canadian Transition to
2010 17(iii) GAAP IFRS IFRS
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue
Oil and gas sales 200,669 - 200,669
Realized gain on hedges 30,124 - 30,124
Royalties (25,693) - (25,693)
----------------------------------------------------------------------------
Petroleum and natural
gas sales, net 205,100 - 205,100
----------------------------------------------------------------------------
Expenses
Operating 13,634 - 13,634
Transportation 4,798 - 4,798
General and
administrative (f) 4,434 (39) 4,395
Future performance based
compensation (d) 11,435 (3,086) 8,349
Interest 14,518 - 14,518
Accretion of
decommissioning
liability (c) - 505 505
Depletion and
depreciation (f) 64,549 (7,713) 56,836
----------------------------------------------------------------------------
113,368 (10,333) 103,035
----------------------------------------------------------------------------
Earnings before taxes 91,732 10,333 102,065
----------------------------------------------------------------------------
Taxes
Deferred income tax
recovery (e) 2,405 525 2,930
----------------------------------------------------------------------------
Earnings for the year 94,137 10,858 104,995
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Other comprehensive
income (loss)
Change in unrealized
gain (loss) on cash
flow hedges (e) 54,681 (4,955) 49,726
Realized (gain) loss on
cash flow hedges (30,124) - (30,124)
----------------------------------------------------------------------------
Comprehensive income for
the year 118,694 5,903 124,597
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(ii) Reconciliation of
earnings and
comprehensive income Effect of
for the year ended Notes Canadian Transition to
December 31, 2010 17(iii) GAAP IFRS IFRS
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue
Oil and gas sales 275,081 - 275,081
Realized gain on hedges 44,345 - 44,345
Royalties (33,405) - (33,405)
----------------------------------------------------------------------------
Petroleum and natural
gas sales, net 286,021 - 286,021
----------------------------------------------------------------------------
Expenses
Operating 18,415 - 18,415
Transportation 6,954 - 6,954
General and
administrative (f) 6,518 (2,880) 3,638
Performance based
compensation (d) 29,864 - 29,864
Future performance based
compensation (d) 3,978 (1,680) 2,298
Interest 20,057 - 20,057
Accretion of
decommissioning
liability (c) - 683 683
Depletion and
depreciation (f) 94,184 (10,414) 83,770
Gains on divestitures (f) - (2,249) (2,249)
----------------------------------------------------------------------------
179,970 (16,540) 163,430
----------------------------------------------------------------------------
Earnings before taxes 106,051 16,540 122,591
----------------------------------------------------------------------------
Taxes
Deferred income tax
recovery (e) 15,787 62,036 77,823
----------------------------------------------------------------------------
Earnings for the year 121,838 78,576 200,414
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Other comprehensive
income (loss)
Change in unrealized
gain (loss) on cash
flow hedges (e) 55,295 344 55,639
Realized (gain) loss on
cash flow hedges (44,345) - (44,345)
----------------------------------------------------------------------------
Comprehensive income for
the year 132,788 78,920 211,708
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(iii) Notes to the reconciliation of balance sheet, income statement and
comprehensive income from Canadian GAAP to IFRS
(a) The Company has elected under IFRS 1 First-time Adoption of IFRS to measure
oil and gas assets at the date of transition to IFRS on a deemed cost basis. The
Canadian GAAP full cost pool was measured upon transition to IFRS as follows:
(i) No exploration or evaluation assets were reclassified from the full cost
pool to exploration and evaluation assets; and
(ii) All costs recognized under Canadian GAAP under the full cost pool were
allocated to the producing assets and undeveloped proved properties on a pro
rata basis using reserve volumes.
(b) The recognition and measurement of impairment differs under IFRS from
Canadian GAAP. In accordance with IFRS 1 the Company performed an assessment of
impairment for all property, plant and equipment and other corporate assets at
the date of transition. The testing on transition to IFRS did not result in
impairment.
(c) Under Canadian GAAP asset retirement obligations were discounted at a credit
adjusted risk free rate. Under IFRS the estimated cash flow to abandon and
remediate the wells and facilities has been risk adjusted and the provision is
discounted at a risk free rate. Upon transition to IFRS this resulted in a $7.0
million increase in the decommissioning provision with a corresponding decrease
in retained earnings.
As a result of the change in the decommissioning provision, accretion expense
for the three and nine month periods ended September 30, 2010 and for the year
ended December 31, 2010 was $0.2 million, $0.5 million and $0.7 million,
respectively. In addition, under Canadian GAAP accretion of the discount was
included in depletion and depreciation. Under IFRS it is included in accretion
of decommissioning liability.
(d) Under Canadian GAAP, the Company recognized an expense related to their
share-based payments on an intrinsic value basis. Under IFRS, the Company is
required to recognize the expense using a fair value model and estimate a
forfeiture rate. This increased provision for performance based compensation and
decreased retained earnings at the date of transition by $1.4 million.
For the three and nine month periods ended September 30, 2010 and year ended
December 31, 2010 performance based compensation expense increased by $1.5
million and decreased by $3.1 million and $1.7 million, respectively with a
corresponding increase in retained earnings.
(e) Under IFRS it is required to account for the rate applicable to a trust
rather than the rate applicable to a corporation. The reversal amounts related
to the rate differential under the trust rate of 39% rather than the corporate
rate of 25% which fully reversed in the comparative period. The result is that
under IFRS the deferred tax liability at January 1, 2010 was $68.5 million
higher than under Canadian GAAP with the offset a result of rate differential
specific to the following three separate components.
First - The rate change on the tax pools of the Company is a $65.8 million
reduction to retained earnings.
Second - The rate change on the Marked-to-Market of financial instruments is a
$3.5 million to reduction to accumulated other comprehensive income.
Third - The rate change on the share issuance costs is a credit of $0.8 million
to shareholders' capital.
After conversion to a Corporation on December 31, 2010 the rates applicable to
the above would revert back to the 25% and an income inclusion in the period of
$65.0 million substantially reversed the deferred tax liability and related
account impacts.
(f) Upon transition to IFRS, the Company adopted a policy of depleting oil and
natural gas interests on a unit of production basis over proved plus probable
reserves. The depletion policy under Canadian GAAP was based on units of
production over total proved reserves, less undeveloped land. In addition
depletion was calculated at the Canadian cost centre level under Canadian GAAP.
IFRS requires depletion and depreciation to be calculated at a unit of account
level.
There was no impact of this difference on adoption of IFRS at January 1, 2010 as
a result of the IFRS 1 election as discussed in Note 17(i)(c).
For the three and nine month periods ended September 30, 2010 and year ended
December 31, 2010 the change in policy to deplete oil and natural gas interest
on proved plus probable reserves, the inclusion of undeveloped land and
component accounting resulted in a net decrease to depletion and depreciation of
$2.4 million, $7.7 million and $10.4 million with a corresponding change to
property, plant and equipment.
As a result of specific general and administrative recoveries guidance under
IFRS, the company has adjusted capitalized costs for the three and nine month
periods ended September 30, 2010 and year ended December 31, 2010 by an increase
of $0.4 million and a decrease of $0.1 million and $2.9 million to general and
administrative expense, respectively with a corresponding increase in retained
earnings.
(iii) Adjustments to the statement of cash flows
The transition from Canadian GAAP to IFRS had no material impact on cash flows
generated by the Company.
Officers
Darren Gee Glenn Booth
President and Chief Executive Officer Vice President, Land
Scott Robinson David Thomas
Executive Vice President and Chief Operating Vice President, Exploration
Officer
Kathy Turgeon Jean-Paul Lachance
Vice President, Finance and Chief Financial Vice President, Exploitation
Officer
Stephen Chetner
Corporate Secretary
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
Royal Bank of Canada
Canadian Imperial Bank of Commerce
BNP Paribas (Canada)
HSBC Bank Canada
Alberta Treasury Branches
Canadian Western Bank
Transfer Agent
Valiant Trust Company
Head Office
1500, 250 - 2nd Street SW
Calgary, AB
T2P 0C1
Phone: 403.261.6081
Fax: 403.451.4100
Web: http://www.peyto.com/
Stock Listing Symbol: PEY.TO Toronto Stock Exchange
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