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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. ("Peyto") (TSX:PEY.UN) is pleased to
present its operating and financial results for the first quarter of the 2011
fiscal year. Peyto grew production 53% year over year or 32% per share since Q1
2010, while generating first quarter operating margins of 75%(1) and profit
margins of 32%(2). First quarter 2011 highlights were as follows:
-- Production grew to 189 MMcfe/d (31,531 boe/d) in Q1 2011 from 124
MMcfe/d (20,653 boe/d) in Q1 2010, as a result of the ongoing
development of Peyto's liquids rich, Deep Basin gas plays, which equates
to a 32% increase per share, a 56% increase on an absolute basis, and a
48% increase in production per share, debt adjusted (3). This is the
sixth consecutive quarter of production per share growth.
-- Funds from operations ("FFO") increased 27% to $74.7 million in Q1 2011
from $58.8 million in Q1 2010. The 19% year over year drop in realized
commodity prices from $7.17/mcfe to $5.85/mcfe was more than offset by
the increased production volumes. FFO per share were up 10% to
$0.56/share.
-- Industry leading operating costs were reduced a further 5% to $0.39/mcfe
($2.32/boe) from Q1 2010 or $0.51/mcfe ($3.08/boe) including
transportation. Cash netbacks were 16% lower at $4.39/Mcfe ($26.32/boe),
or 75% of revenue due to lower natural gas prices.
-- Capital expenditures of $103.8 million (net of $0.6 million in Drilling
Royalty Credits) were invested in the quarter, up 109% from $49.7
million in Q1 2010. A total of 21 wells were drilled during the period.
-- Earnings of $31.7 million ($0.24/share) were generated in the quarter
while dividends of $23.9 million ($0.18/share) were paid to
shareholders, representing a before tax payout of 32% of FFO.
First Quarter 2011 in Review
Peyto continued aggressively developing its extensive Deep Basin opportunities
in the quarter investing twice as much capital as a year ago into high return
projects. By the end of the quarter, the capital program was responsible for
approximately 40 MMcfe/d (6,800 boe/d) of new production. When combined with the
high netbacks from liquids rich natural gas and a unique low cost structure,
this production growth delivered strong growth in funds from operations. Peyto
continued to apply the horizontal multi-stage fracture well design to the
development of additional Deep Basin tight gas reservoirs and over the past
quarter enjoyed repeated success in the Falher formation. This proven success
increases the company's extensive inventory of undeveloped Falher opportunities.
In the fall of 2009, when Peyto began development of its Wilrich play, total
Wilrich production was 100 boe/d. At the end of Q1 2011 the Wilrich play was
producing 8,500 boe/d. The company believes the Falher play will offer similar
potential. In anticipation of increasing production volumes, Peyto further
expanded its infrastructure of wholly owned and operated pipelines and gas
processing facilities, ensuring "just in time" available capacity. With Alberta
natural gas prices averaging less than $4/GJ during the quarter, Peyto's
unwavering focus on cost control maintained all-in cash costs below $1.50/mcfe.
The strong financial and operating performance resulted in an annualized 15%
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 gain/losses.
2. Profit Margin is defined as Net Earnings for the quarter divided by
Revenue before Royalties but including realized hedging gain/losses.
3. Per share results are adjusted for changes in net debt and equity. Net
debt is converted to equity using a Mar 31 share price of $20.60 for
2011 and $13.51 for 2010.
Natural gas volumes recorded in thousand cubic feet (mcf) are converted
to barrels of oil equivalent (boe) using the ratio of six (6) thousand
cubic feet to one (1) barrel of oil (bbl). Natural gas liquids and oil
volumes in barrel of oil (bbl) are converted to thousand cubic feet
equivalent (mcfe) using a ratio of one (1) barrel of oil to six (6)
thousand cubic feet. This could be misleading if used in isolation as it
is based on an energy equivalency conversion method primarily applied at
the burner tip and does not represent a value equivalency at the
wellhead.
----------------------------------------------------------------------------
3 Months Ended Mar. 31 %
2011 2010 Change
----------------------------------------------------------------------------
Operations
Production
Natural gas (mcf/d) 166,710 103,934 60%
Oil & NGLs (bbl/d) 3,746 3,330 12%
Thousand cubic feet equivalent
(mcfe/d @ 1:6) 189,187 123,916 53%
Barrels of oil equivalent
(boe/d @ 6:1) 31,531 20,653 53%
Product prices
Natural gas ($/mcf) 4.92 6.34 (22)%
Oil & NGLs ($/bbl) 76.19 68.93 11%
Operating expenses ($/mcfe) 0.39 0.41 (5)%
Transportation ($/mcfe) 0.13 0.13 -
Field netback ($/mcfe) 4.75 5.81 (18)%
General & administrative
expenses ($/mcfe) 0.09 0.14 (36)%
Interest expense ($/mcfe) 0.27 0.40 (33)%
Financial ($000, except per
share)
Revenue 99,577 79,974 25%
Royalties 9,922 9,173 8%
Funds from operations 74,696 58,849 27%
Funds from operations per share 0.56 0.51 10%
Total dividends 23,921 41,471 (42)%
Total dividends per share 0.18 0.36 (50)%
Payout ratio 32 71 (55)%
Earnings 31,688 40,628 (22)%
Earnings per diluted share 0.24 0.35 (31)%
Capital expenditures 103,786 49,651 109%
Weighted average common shares
outstanding 132,737,066 115,153,667 15%
As at March 31
Net debt (before future
compensation expense and
unrealized hedging gains) 453,376 467,368 (30)%
Shareholders' equity 850,442 560,405 52%
Total assets 1,528,599 1,323,962 15%
----------------------------------------------------------------------------
Three Months ended Mar. 31
($000) 2011 2010
----------------------------------------------------------------------------
Cash flows from operating activities 42,888 52,674
Change in non-cash working capital 27,585 5,369
Change in provision for performance based
compensation 4,223 806
----------------------------------------------------------------------------
Funds from operations 74,696 58,849
----------------------------------------------------------------------------
Funds from operations per share 0.56 0.51
----------------------------------------------------------------------------
(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 distributions may vary.
Exploration & Development
Over the past twelve years, Peyto has been a leader in the exploration and
development of natural gas in Alberta's Deep Basin. In this area, the company
has developed more production and reserves with the drill bit than any other
operator over that time frame. This track record of profitably exploring and
developing natural gas in the Deep Basin continues today with recent success in
the Notikewin, Falher and Wilrich formations. In total, 45 horizontal wells have
been drilled and brought on stream from these three formations. Collectively,
these plays currently account for over 16,000 boe/d of production growth, while
their proven success has added over 300 horizontal locations to future drilling
inventory.
The successful application of multi-stage fractured horizontal wells in
reservoirs that were previously dismissed as uneconomic has created renewed
interest both within Peyto's land base and in other areas of the Deep Basin.
Peyto's exploration team will continue to evaluate and advance these plays
alongside the company's already extensive inventory of proven opportunities.
Capital Expenditures
At the end of 2010, Peyto converted to a dividend paying growth corporation as
part of a plan to deliver more return to investors through growth. The goal has
always been to deliver the maximum total return to investors, which for Peyto,
is a combination of growth in the asset value per share plus dividends. History
has shown, when there is profitable growth in Peyto's production and reserves
per share, that growth is reflected in the share price.
In keeping with the conversion plan to a growth oriented energy company, first
quarter 2011 capital investments were $103.8 million (net of $0.6 million in
Drilling Royalty Credits) or 109% greater than Q1 2010. The company invested
$51.2 million on drilling, $32.8 million on completions and $7.0 million
connecting and equipping new wells. Facility expansions at Nosehill and Wildhay
gas plants accounted for $7.7 million, while the remaining $5.7 million was
spent acquiring new opportunities.
During the quarter, 21 gross (17.7 net) wells were drilled, 18 gross (16.6 net)
zones were completed and 17 gross (15.2 net) zones brought on stream.
Approximately 90% of these new wells were horizontal wells.
An expansion began at the Peyto Wildhay gas plant in the quarter, to increase
the capacity from 25 MMcf/d to 50 MMcf/d with the addition of two new
compressors and another refrigeration plant. A compressor addition at the
Nosehill gas plant increased capacity there from 50 MMcf/d to 60 MMcf/d.
The company successfully secured new opportunities in the quarter, purchasing 7
net sections (4,480 acres) of undeveloped land at Crown land sales, as well as
acquiring partner interest in 10 sections of partially developed lands. Peyto's
targeted approach to acquiring new lands has delivered incredible returns and
impressive growth over its twelve year history. Historically, Peyto has
developed over 10 bcf in every net section of undeveloped land it acquires in
the Deep Basin.
Financial Results
Peyto realized a natural gas price, before hedging gains, of $4.05/mcf in the
first quarter from an average Alberta gas price of $3.53/GJ. An average liquids
price of $76.19/bbl was also realized which represents approximately 86% of the
Edmonton light oil par price of $88.44/bbl. The natural gas and liquids
production streams, currently equating to 88% and 12% of total production
respectively, combined for unhedged revenue of $5.08/mcfe, or approximately 40%
more than the dry gas price. Hedging activity yielded gains of $13.1 million or
$0.77/mcf for total revenue of $5.85/mcfe.
Royalties of $0.58/mcfe, operating costs of $0.39/mcfe, transportation of
$0.13/mcfe, interest of $0.27/mcfe and G&A expenses of $0.09/mcfe all combined
for a total cash cost of $1.46/mcfe. This industry leading, low cost structure
delivered a cash netback of $4.39/mcfe ($26.32/boe) or 75% of revenue.
DD&A, based on Proved plus Probable Additional reserves, of $1.70/mcfe, as well
as a provision for future performance based compensation and deferred income
tax, yielded earnings of $1.86/mcfe or a 32% profit margin.
Peyto's year-end 2010 net debt increased by $48 million to $453 million at Q1
2011. This leaves approximately $172 million on available bank lines of $625
million. Peyto chose not to increase the available borrowing capacity in order
to minimize standby charges and other fees.
Marketing
Natural gas prices in the first quarter 2011 increased slightly from the
previous two quarters as prolonged winter weather decreased North American gas
storage levels to below the five year average. Canadian natural gas prices did
not increase the same as US prices, as a rising Canadian to US currency exchange
rate countered much of the US price improvement. Peyto realized gains during the
quarter from its previous forward sales of natural gas with a Q1 2011 hedging
gain of $13.1 million. As well, Peyto continued to layer in future sales in an
effort to smooth out the natural gas price volatility.
As at March 31, 2011, Peyto had committed to the future sale of 35,230,000
gigajoules (GJ) of natural gas at an average price of $4.41 per GJ or $5.16 per
mcf. Had these contracts been closed on March 31, 2011, Peyto would have
realized a gain in the amount of $18.7 million.
Activity Update
Peyto is pleased to report that current production has reached 35,000 boe/d (210
mmcfe/d) and represents a company record for production per share, before
accounting for the $1.2 billion in distributions and dividends that has been
paid to shareholders. Peyto's plan to continue drilling operations through
spring breakup remains intact for four of the six drilling rigs currently under
contract and should position the company with several wells ready for quick
completion and connection in late May or early June.
To date, 25 gross (21.7 net) wells have been drilled and 25 gross (23.2 net)
wells brought on stream. This activity has added over 10,000 boe/d of new
production so far this year.
Outlook
The company continues to use its low cost advantage and strong financial
position to aggressively and profitably build shareholder value. The quality of
Peyto's projects and its ability to control costs make it one of a select few
natural gas producers that can profitably build value in the current depressed
gas price environment. In general, the natural gas industry in North America has
a high cost structure and a relatively short reserve life, making it difficult
to replace natural declines with new production. History has shown that
depressed gas price environments eventually result in declining supply which
leads to higher prices.
Conference Call and Webcast
A conference call will be held with the senior management of Peyto to answer
questions with respect to the 2011 first quarter financial results on Thursday,
May 12th, 2011, at 9:00 a.m. Mountain Daylight Time (MDT), or 11:00 a.m. Eastern
Daylight Time (EDT). 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. MDT, 1:00 p.m. EDT Thursday, May 12th, 2011 until midnight EDT on
Thursday, May 19th, 2011. The conference call can also be accessed through the
internet at http://events.digitalmedia.telus.com/peyto/051211/index.php. After
this time the conference call will be archived on the Peyto Exploration &
Development website at www.peyto.com.
Annual General Meeting
Peyto shareholders are invited to attend the Annual General Meeting of
Shareholders which is scheduled for 3:00 p.m. on Wednesday, May 18, 2011 at
Livingston Place Conference Centre, +15 level, 222-3rd Avenue SW, Calgary,
Alberta.
Management's Discussion and Analysis
Management's Discussion and Analysis of this first quarter report is available
on the Peyto website at http://www.peyto.com/news/Q12011MDandA.pdf. A complete
copy of the first quarter report to Shareholders, including the Management's
Discussion and Analysis, and financial statements and related notes is also
available at www.peyto.com and will be filed at SEDAR, www.sedar.com , at a
later date.
Shareholders are encouraged to visit the Peyto website at www.peyto.com where
there is a wealth of information designed to inform and educate investors. A
monthly President's Report can also be found on the website which follows the
progress of the capital program and the ensuing production growth.
Darren Gee, President and CEO
May 11, 2011
Certain information set forth in this document and Management's Discussion and
Analysis, including management's assessment of Peyto's future plans and
operations, contains forward-looking statements. By their nature,
forward-looking statements are subject to numerous risks and uncertainties, some
of which are beyond these parties' control, including the impact of general
economic conditions, industry conditions, volatility of commodity prices,
currency fluctuations, imprecision of reserve estimates, environmental risks,
competition from other industry participants, the lack of availability of
qualified personnel or management, stock market volatility and ability to access
sufficient capital from internal and external sources. Readers are cautioned
that the assumptions used in the preparation of such information, although
considered reasonable at the time of preparation, may prove to be imprecise and,
as such, undue reliance should not be placed on forward-looking statements.
Peyto's actual results, performance or achievement could differ materially from
those expressed in, or implied by, these forward-looking statements and,
accordingly, no assurance can be given that any of the events anticipated by the
forward-looking statements will transpire or occur, or if any of them do so,
what benefits Peyto will derive therefrom.
Peyto Exploration & Development Corp.
Condensed Balance Sheet (unaudited)
(Amounts in $ thousands, except as otherwise noted)
----------------------------------------------------------------------------
March 31 December 31 January 1
2011 2010 2010
----------------------------------------------------------------------------
Assets
Current assets
Cash 10,740 7,894 -
Accounts receivable (Note 3) 52,522 55,876 58,305
Due from private placement
(Note 8) - 12,423 2,728
Financial derivative
instruments (Note 14) 19,454 25,247 8,683
Prepaid expenses (Note 4) 3,597 3,280 3,786
----------------------------------------------------------------------------
86,313 104,720 73,502
----------------------------------------------------------------------------
Prepaid capital - - 955
Financial derivative
instruments (Note 14) - 2,664 1,254
Property, plant and equipment,
net (Note 5) 1,442,286 1,367,869 1,178,402
----------------------------------------------------------------------------
1,442,286 1,370,533 1,180,611
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1,528,599 1,475,253 1,254,113
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable and accrued
liabilities 86,432 113,592 55,890
Dividends payable (Note 8) 7,984 15,825 13,790
Provision for future
performance based compensation
(Note 12) 8,470 5,340 3,395
----------------------------------------------------------------------------
102,886 134,757 73,075
----------------------------------------------------------------------------
Long-term debt (Note 6) 425,000 355,000 435,000
Financial derivative
instruments (Note 14) 754 - -
Provision for future
performance based compensation
(Note 12) 2,462 1,369 1,016
Decommissioning provision (Note 7) 24,562 24,734 17,479
Deferred income taxes (Note 13) 122,492 114,610 191,907
----------------------------------------------------------------------------
575,270 495,713 645,402
----------------------------------------------------------------------------
Shareholders' or Unitholders'
equity
Shareholders' capital (Note 8) 777,778 755,831 -
Unitholders' capital (Note 8) - - 501,219
Shares or Units to be issued
(Note 8) - 17,285 2,728
Retained earnings 58,541 50,774 25,627
Accumulated other comprehensive
income (Note 8) 14,124 20,893 6,062
----------------------------------------------------------------------------
850,443 844,783 535,636
----------------------------------------------------------------------------
1,528,599 1,475,253 1,254,113
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Approved by the Board of Directors
(signed) "Michael MacBean" (signed) "Darren Gee"
Director Director
Peyto Exploration & Development Corp.
Condensed Income Statement (unaudited)
(Amounts in $ thousands)
Three months ended
March 31 March 31
2011 2010
----------------------------------------------------------------------------
Revenue
Oil and gas sales 86,458 74,090
Realized gain on hedges (Note 14) 13,119 5,884
Royalties (9,922) (9,173)
----------------------------------------------------------------------------
Petroleum and natural gas sales, net 89,655 70,801
----------------------------------------------------------------------------
Expenses
Operating (Note 9) 6,571 4,559
Transportation 2,163 1,435
General and administrative (Note 10) 1,607 1,546
Future performance based compensation (Note 12) 4,223 806
Interest (Note 11) 4,618 4,412
Accretion of decommissioning liability (Note 11) 232 178
Depletion and depreciation (Note 5) 29,026 17,746
Gains on divestitures (818) -
----------------------------------------------------------------------------
47,622 30,682
----------------------------------------------------------------------------
Earnings before taxes 42,033 40,119
----------------------------------------------------------------------------
Taxes
Deferred income tax expense (recovery)
(Note 13) 10,345 (509)
----------------------------------------------------------------------------
Earnings for the period 31,688 40,628
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Earnings per share or unit (Note 8)
Basic and diluted $ 0.24 $ 0.35
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted average number of common shares
outstanding (Note 8)
Basic and diluted 132,737,066 115,153,667
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Peyto Exploration & Development Corp.
Condensed Statement of Comprehensive Income (unaudited)
(Amounts in $ thousands)
Three months ended
March 31 March 31
2011 2010
----------------------------------------------------------------------------
Earnings for the period 31,688 40,628
Other comprehensive income
Change in unrealized gain on cash flow hedges
(net of deferred tax, 2011 - $2.4 million
recovery (2010 - $10.3 million expense)) 6,350 27,620
Realized (gain) loss on cash flow hedges (13,119) (5,884)
----------------------------------------------------------------------------
Comprehensive Income 24,919 62,364
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Peyto Exploration & Development Corp.
Condensed Statement of Changes in Equity (unaudited)
(Amounts in $ thousands)
Three months ended
March 31 March 31
2011 2010
----------------------------------------------------------------------------
Shareholders' / Unitholders' capital,
Beginning of Year 755,831 501,219
----------------------------------------------------------------------------
Common shares / trust units issued by private
placement 17,150 2,728
Common share issuance costs (net of tax) (65) -
Trust units issued pursuant to DRIP 1,973 1,505
Trust units issued pursuant to OTUPP 2,889 872
----------------------------------------------------------------------------
Shareholders' / Unitholders' capital, End of
Period 777,778 506,324
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Common shares to be issued, Beginning of Year 17,285 2,728
----------------------------------------------------------------------------
Common shares issued (17,285) (2,728)
Common shares to be issued - 1,498
----------------------------------------------------------------------------
Common shares to be issued, End of Period - 1,498
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Retained earnings, Beginning of Year 50,774 25,627
----------------------------------------------------------------------------
Earnings for the period 31,688 40,628
Dividends (Note 8) (23,921) (41,470)
----------------------------------------------------------------------------
Retained earnings, End of Period 58,541 24,785
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated other comprehensive income,
Beginning of Year 20,893 6,062
----------------------------------------------------------------------------
Other comprehensive income (loss) (6,769) 21,736
----------------------------------------------------------------------------
Accumulated other comprehensive income, End of
Period 14,124 27,798
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Shareholders' Equity 850,443 560,405
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Peyto Exploration & Development Corp.
Condensed Statement of Cash Flows(unaudited)
(Amounts in $ thousands)
Three months ended
March 31 March 31
2011 2010
----------------------------------------------------------------------------
Cash provided by (used in)
Operating Activities
Earnings 31,688 40,628
Items not requiring cash:
Deferred income tax 10,345 (509)
Depletion and depreciation 29,026 17,746
Gain on disposition of assets (818) -
Accretion of decommissioning liability 232 178
Change in non-cash working capital related to
operating activities (Note 17) (27,585) (5,369)
----------------------------------------------------------------------------
42,888 52,674
----------------------------------------------------------------------------
Financing Activities
Issuance of common shares 4,727 1,654
Issuance costs (86) -
Dividends paid (23,921) (39,250)
Increase in bank debt 70,000 15,000
Change in non-cash working capital related to
financing activities (Note 17) 4,582 2,058
----------------------------------------------------------------------------
55,302 (20,538)
----------------------------------------------------------------------------
Investing Activities
Additions to property, plant and equipment,
net (103,028) (48,763)
Change in non-cash working capital related to
investing activities (Note 17) 7,684 16,627
----------------------------------------------------------------------------
(95,344) (32,136)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net increase (decrease) in cash 2,846 -
Cash, beginning of year 7,894 -
----------------------------------------------------------------------------
Cash, end of period 10,740 -
----------------------------------------------------------------------------
Peyto Exploration & Development Corp.
Notes to Condensed Financial Statements (unaudited)
As at March 31, 2011
(Amounts 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
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, units of
Peyto Energy Trust (the "Trust") were exchanged for common shares of Peyto on a
one-for-one basis (see Note 8).
The conversion has been accounted for as a continuity of interests and all
comparative information presented for the pre-conversion period is that of the
Trust. All transaction costs associated with the conversion were expensed as
incurred as general and administration expense.
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 May 10, 2011.
2. Basis of presentation
These unaudited condensed financial statements ("financial statements") for the
three months ended March 31, 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 months
ended March 31, 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 in Note 2 below. Reconciliations and descriptions relating to
the transition from Canadian GAAP to IFRS are included in Note 19.
a) Summary of significant accounting policies
The precise determination of many assets and liabilities is dependent upon
future events, the preparation of periodic financial statements necessarily
involves the use of estimates and approximations. Accordingly, actual results
could differ from those estimates. The 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, net
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: "held for trading"; "loans &
receivables"; and "other liabilities". Subsequent measurement of the financial
instruments is based on their classification. Unrealized gains and losses on
held for trading financial instruments are recognized in earnings. The other
categories of financial instruments are recognized at amortized cost using the
effective interest rate method. The Company has made the following
classifications:
----------------------------------------------------------------------------
Financial Assets & Liabilities Category
----------------------------------------------------------------------------
Cash Held for trading
----------------------------------------------------------------------------
Accounts Receivable Loans & receivables
----------------------------------------------------------------------------
Due from Private Placement Loans & receivables
----------------------------------------------------------------------------
Accounts Payable and Accrued Liabilities Other Liabilities
----------------------------------------------------------------------------
Provision for Future Performance Based Compensation Other Liabilities
----------------------------------------------------------------------------
Dividends Payable Other Liabilities
----------------------------------------------------------------------------
Long Term Debt Other Liabilities
----------------------------------------------------------------------------
Financial Derivative Instruments Held for trading
----------------------------------------------------------------------------
Derivative Instruments and Risk Management
Derivative instruments are utilized by the Company to manage market risk against
volatility in commodity prices. The Company's policy is not to utilize
derivative instruments for speculative purposes. The Company has chosen to
designate its existing derivative instruments as cash flow hedges. The Company
assesses, on an ongoing basis, whether the derivatives that are used as cash
flow hedges are highly effective in offsetting changes in cash flows of hedged
items. All derivative instruments are recorded on the balance sheet at their
fair value. The effective portion of the gains and losses is recorded in other
comprehensive income until the hedged transaction is recognized in earnings.
When the earnings impact of the underlying hedged transaction is recognized in
the condensed statement of earnings, the fair value of the associated cash flow
hedge is reclassified from other comprehensive income into earnings. Any hedge
ineffectiveness is immediately recognized in earnings. The fair values of
forward contracts are based on forward market prices.
Embedded Derivatives
An embedded derivative is a component of a contract that causes some of the cash
flows of the combined instrument to vary in a way similar to a stand-alone
derivative. This causes some or all of the cash flows that otherwise would be
required by the contract to be modified according to a specified variable, such
as interest rate, financial instrument price, commodity price, foreign exchange
rate, a credit rating or credit index, or other variables to be treated as a
financial derivative. The Company has no contracts containing embedded
derivatives.
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
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 significant impact on the Company's financial position
or results.
3. Accounts receivable
March 31 December 31 January 1
2011 2010 2010
----------------------------------------------------------------------------
Accounts receivable - general 45,367 48,721 51,150
Accounts receivable - tax 7,155 7,155 7,155
----------------------------------------------------------------------------
52,522 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. Prepaid expenses
March 31 December 31 January 1
2011 2010 2010
----------------------------------------------------------------------------
Prepaid operating and interest
expenses 3,597 3,280 3,786
----------------------------------------------------------------------------
3,597 3,280 3,786
----------------------------------------------------------------------------
----------------------------------------------------------------------------
5. 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 96,423 7,656 - 104,079
Dispositions (698) - - (698)
----------------------------------------------------------------------------
At March 31, 2011 1,462,682 92,616 1,007 1,556,305
----------------------------------------------------------------------------
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 (27,900) (1,107) (19) (29,026)
Dispositions 62 - - 62
----------------------------------------------------------------------------
At March 31, 2011 (108,302) (4,974) (743) (114,019)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net book value at March 31,
2011 1,354,380 87,642 264 1,442,286
----------------------------------------------------------------------------
----------------------------------------------------------------------------
During the period, the Company capitalized $1.2 million (2010 - $1.1 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.
6. Long-term debt
The Company has a syndicated $625 million extendible revolving credit facility
with a stated term date of April 30, 2011. The facility is made up of a $20
million working capital sub-tranche and a $605 million production line. The
facilities are available on a revolving basis for a period of at least 364 days
and upon the term out date may be extended for a further 364 day period at the
request of the Company, subject to approval by the lenders. In the event that
the revolving period is not extended, the facility is available on a
non-revolving basis for a further one year term, at the end of which time the
facility would be due and payable. Outstanding amounts on this facility bear
interest at rates determined by the Company's debt to 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.
Subsequent to March 31, 2011, Peyto's banking syndicate has agreed to extend the
stated term date of the credit facility to April 29, 2012.
Total cash interest expense for the period was $4.6 million (2010 - $4.4
million) and the average borrowing rate for the first quarter of 2011 was 4.7%
(2010 - 4.0%).
7. 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 1,329
Accretion of discount 232
Change in discount rate (1,733)
----------------------------------------------------------------------------
Balance, March 31, 2011 (2) 24,562
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Current -
Non-current 24,562
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 $91.1 million to be
incurred over the next 50 years at an inflation rate of 2% and a
discount rate of 3.75%.
8. Shareholders' capital and Unitholders' capital
Authorized: Unlimited number of voting common shares
Issued and Outstanding
Common Shares and Units (no par value) Number of Amount
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) - (65)
Common shares issued pursuant to DRIP 113,527 1,973
Common shares issued pursuant to OTUPP 166,196 2,889
----------------------------------------------------------------------------
Balance, March 31, 2011 133,061,301 777,778
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 during the period of 132,737,066 (2010 -
115,153,667). There are no dilutive instruments outstanding.
Dividends
During the three months ended March 31, 2011, Peyto declared and paid dividends
of $0.18 per common share or $0.06 per common share per month, totaling $23.9
million (2010 - $0.36 per share or $0.12 per share per month, $41.5 million).
Comprehensive Income
Comprehensive income consists of earnings and other comprehensive income
("OCI"). OCI comprises the change in the fair value of the effective portion of
the derivatives used as hedging items in a cash flow hedge. "Accumulated other
comprehensive income" is a equity category comprised of the cumulative amounts
of OCI.
Accumulated hedging gains
2011
----------------------------------------------------------------------------
Balance, January 1, 2011 20,893
Hedging gains (losses) (6,769)
----------------------------------------------------------------------------
Balance, March 31, 2011 14,124
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 14.
9. 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
March 31 March 31
2011 2010
----------------------------------------------------------------------------
Field expenses 8,735 7,132
Processing and gathering recoveries (2,164) (2,573)
----------------------------------------------------------------------------
Total operating expenses 6,571 4,559
----------------------------------------------------------------------------
----------------------------------------------------------------------------
10. General and administrative expenses
General and administrative expenses are reduced by operating and capital
overhead recoveries from operated properties.
Three months ended
March 31 March 31
2011 2010
----------------------------------------------------------------------------
General and administrative expenses 3,065 2,718
Overhead recoveries (1,458) (1,172)
----------------------------------------------------------------------------
Net general and administrative expenses 1,607 1,546
----------------------------------------------------------------------------
----------------------------------------------------------------------------
11. Finance costs
Three months ended
March 31 March 31
2011 2010
----------------------------------------------------------------------------
Cash interest expense 4,618 4,412
Accretion of discount on provisions 232 178
----------------------------------------------------------------------------
4,850 4,590
----------------------------------------------------------------------------
----------------------------------------------------------------------------
12. 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:
March 31 December 31
2011 2010
----------------------------------------------------------------------------
Share price $20.60 $18.49
Exercise price $9.56 - $18.83 $6.62 - $11.66
Expected volatility 23% - 48% 0% - 28%
Option life 1 year 1 - 2 years
Dividend yield 0% 0%
Risk-free interest rate 1.77% 1.66%
----------------------------------------------------------------------------
13. Deferred taxes
On December 31, 2010, the Company converted from a publicly traded income trust
to a publicly traded corporation by way of the 2010 Arrangement (see Note 1). As
a result, for the period ended March 31, 2011, the Company's deferred income tax
expense was calculated on the basis of it being a corporation. For the period
ended March 31, 2010, the Company's deferred income tax recovery was calculated
on the basis of it being a publicly traded income trust in accordance with
legislation applicable to certain income trusts.
Three months ended
March 31 March 31
2011 2010
----------------------------------------------------------------------------
Earnings before income tax 42,033 40,118
Statutory income tax rate 26.50% 39.00%
----------------------------------------------------------------------------
Expected income taxes 11,139 15,646
Increase (decrease) in income tax rate change (660) -
Income distributed by the Trust - (16,174)
Other (134) 18
----------------------------------------------------------------------------
Deferred income tax (recovery) expense 10,345 (510)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Difference between tax base and reported
amounts for depreciable assets (134,249) (197,834)
Decommissioning liability 6,141 7,121
Alberta royalty tax credits 4,964 -
Share issuance costs 2,699 1,495
Financial derivative instruments 2,610 2,034
Future performance based bonuses (4,916) (17,553)
Tax loss carry-forwards recognized 259 -
----------------------------------------------------------------------------
Deferred income tax liability (122,492) (204,737)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
At March 31, 2011 the Company has tax pools of approximately $913.2 million
(March 31, 2010 - $708.6 million) available for deduction against future income.
The Company has approximately $nil in unrecognized deferred income tax assets
(March 31, 2010 - $6.0 million) and approximately $0.4 in loss carryforwards
(March 31, 2010 - $0.2 million) available to reduce future taxable income.
14. 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 March 31, 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 March
31, 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 March
31, 2011 is as follows:
Fair
Effective Value March 31 December 31
Description Notional(1) Term Rate Level 2011 2010
----------------------------------------------------------------------------
Natural gas
financial swaps - 2011-
AECO 35.2GJ(2) 2012 $4.41/GJ Level 1 18,700 27,911
----------------------------------------------------------------------------
(1) Notional values as at December 31, 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 $3.80/GJ
May 1, 2011 to March 31, 2012 Fixed Price 5,000 GJ $4.00/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
----------------------------------------------------------------------------
As at March 31, 2011, the Company had committed to the future sale of 35,230,000
gigajoules (GJ) of natural gas at an average price of $4.41 per GJ or $5.60 per
mcf based on the historical heating value of Peyto's natural gas. Had these
contracts been closed on March 31, 2011, the Company would have realized a gain
in the amount of $18.7 million. If the AECO gas price on March 31, 2011 were to
increase by $1/GJ, the unrealized gain would decrease by approximately $35.2
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 March 31, 2011 the Company entered into the following contracts:
----------------------------------------------------------------------------
Natural Gas Price
Period Hedged Type Daily Volume (CAD)
----------------------------------------------------------------------------
June 1, 2011 to March 31, 2013 Fixed Price 5,000 GJ $4.17/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 period ended March 31, 2011 would decrease by $1.0 million. An
opposite change in interest rates will result in an opposite impact on earnings.
Credit Risk
A substantial portion of the Company's accounts receivable is with petroleum and
natural gas marketing entities. Industry standard dictates that commodity sales
are settled on the 25th day of the month following the month of production. The
Company generally extends unsecured credit to purchasers, and therefore, the
collection of accounts receivable may be affected by changes in economic or
other conditions and may accordingly impact the Company's overall credit risk.
Management believes the risk is mitigated by the size, reputation and
diversified nature of the companies to which they extend credit. The Company has
not previously experienced any material credit losses on the collection of
accounts receivable. Of the Company's revenue for the period ended March 31,
2011, approximately 86% was received from five companies (24%, 20%, 19%, 13% and
10%) (March 31, 2010 - 87%, six companies (23%, 17%, 14%, 11%, 11% and 11%)). Of
the Company's accounts receivable for the period ended March 31, 2011,
approximately 39% was receivable from three companies (15%, 13% and 11%) (Year
ended December 31, 2010 - 31%, three companies (11%, 10% and 10%)). The maximum
exposure to credit risk is represented by the carrying amount on the
consolidated balance sheet. There are no material financial assets that the
Company considers past due and no accounts have been written off.
The Company may be exposed to certain losses in the event of non-performance by
counterparties to commodity price contracts. The Company mitigates this risk by
entering into transactions with counterparties that have investment grade credit
ratings.
Counterparties to financial instruments expose the Company to credit losses in
the event of non-performance. Counterparties for derivative instrument
transactions are limited to high credit-quality financial institutions, which
are all members of our syndicated credit facility.
The Company assesses quarterly if there should be any impairment of financial
assets. At March 31, 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 project debt financing. The Company
also mitigates liquidity risk by maintaining an insurance program to minimize
exposure to certain losses.
The following are the contractual maturities of financial liabilities as at
March 31, 2011:
less than
1 Year 1-2 Years 2-5 Years Thereafter
----------------------------------------------------------------------------
Accounts payable and accrued
liabilities 86,432
Dividends payable 7,984
Provision for future market and
reserves based bonus 8,470 2,462
Financial derivative instruments 754
Long-term debt(1) 425,000
----------------------------------------------------------------------------
(1) Revolving credit facility renewed annually (see Note 7)
15. Capital disclosures
The Company's objectives when managing capital are: (i) to maintain a flexible
capital structure, which optimizes the cost of capital at acceptable risk; and
(ii) to maintain investor, creditor and market confidence to sustain the future
development of the business.
The Company manages its capital structure and makes adjustments to it in light
of changes in economic conditions and the risk characteristics of its underlying
assets. The Company considers its capital structure to include Shareholders'
equity, debt and working capital. To maintain or adjust the capital structure,
the Company may from time to time, issue common shares, raise debt and/or adjust
its capital spending to manage its current and projected debt levels. The
Company monitors capital based on the following non-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.
March 31 December 31
2011 2010
----------------------------------------------------------------------------
Shareholders' equity 850,443 844,782
Long-term debt 425,000 355,000
Working capital deficit 16,573 30,038
----------------------------------------------------------------------------
1,292,016 1,229,820
----------------------------------------------------------------------------
----------------------------------------------------------------------------
16. 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.
17. Supplemental cash flow information
Changes in non-cash working capital balances
March 31 March 31
2011 2010
----------------------------------------------------------------------------
(Increase)/decrease of assets:
Accounts receivables 3,354 (6,605)
Due from private placement 12,423 2,728
Prepaid expenses (318) 724
Increase/(decrease) of liabilities:
Accounts payable and accrued liabilities (27,160) 16,333
Dividends payable (7,841) (670)
Provision for future performance based
compensation 4,223 806
----------------------------------------------------------------------------
(15,319) 13,316
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Attributable to operating activities (27,585) (5,369)
Attributable to financing activities 4,582 2,058
Attributable to investing activities 7,684 16,627
----------------------------------------------------------------------------
(15,319) 13,316
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2011 2010
----------------------------------------------------------------------------
Cash interest paid 4,618 4,412
Cash taxes paid - -
----------------------------------------------------------------------------
18. Commitments and contingencies
Follwing is a summary of the Company's commitments related to operating
leases as at March 31, 2011.
2011 2012 2013 2014 2015 Thereafter
----------------------------------------------------------------------------
Operating lease 794 1,058 1,058 1,058 - -
----------------------------------------------------------------------------
Total 794 1,058 1,058 1,058 - -
----------------------------------------------------------------------------
The Company has no other contractual obligations or commitments as at March 31,
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, including
the litigation discussed below may be material or may be indeterminate and the
outcome of such litigation may materially impact Peyto's financial position or
results of operations in the period of settlement. While Peyto assesses the
merits of each lawsuit and defends itself accordingly, Peyto may be required to
incur significant expenses or devote significant resources to defending itself
against such litigation. These claims are not currently expected to have a
material impact on Peyto's financial position or results of operations.
19. 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.
These financial statements, for the period ended March 31, 2011, are the first
the Company prepares in accordance with IFRS. 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.
Peyto Exploration &
Development Corp. (unaudited) Effect of
IFRS Balance Sheet as at Notes Canadian Transition to
January 1, 2010 19(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 (f) 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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Peyto Exploration &
Development Corp. (unaudited) Effect of
IFRS Balance Sheet as at Notes Canadian Transition to
March 31, 2010 19(iii) GAAP IFRS IFRS
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Assets
Current assets
Accounts receivable 64,910 - 64,910
Financial derivative
instruments 40,039 - 40,039
Inventory and prepaid expenses 3,064 - 3,064
----------------------------------------------------------------------------
108,013 - 108,013
----------------------------------------------------------------------------
Financial derivative
instruments 4,974 - 4,974
Oil and gas assets (f) 1,207,734 3,241 1,210,975
----------------------------------------------------------------------------
1,212,708 3,241 1,215,949
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1,320,721 3,241 1,323,962
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable and accrued
liabilities 72,222 - 72,222
Distributions payable 13,120 - 13,120
Provision for future
performance based
compensation (d) 3,882 (114) 3,768
----------------------------------------------------------------------------
89,224 (114) 89,110
----------------------------------------------------------------------------
Long-term debt 450,000 - 450,000
Provision for future
performance based
compensation (d) 1,294 155 1,449
Decommissioning provision (c) 10,806 7,455 18,261
Deferred income taxes (e) 125,598 79,139 204,737
----------------------------------------------------------------------------
587,698 86,749 674,447
----------------------------------------------------------------------------
Unitholders' equity
Unitholders' capital (e) 505,512 812 506,324
Units to be issued 1,498 - 1,498
Retained earnings 95,153 (70,368) 24,785
Accumulated other
comprehensive income (e) 41,636 (13,838) 27,798
----------------------------------------------------------------------------
643,799 (83,394) 560,405
----------------------------------------------------------------------------
1,320,721 3,241 1,323,962
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Peyto Exploration &
Development Corp. (unaudited) Effect of
IFRS Balance Sheet as at Notes Canadian Transition to
December 31, 2010 19(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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Peyto Exploration &
Development Corp. (unaudited)
(ii) Reconciliation of
earnings and comprehensive Effect of
income for the period ended Notes Canadian Transition to
March 31, 2010 19(iii) GAAP IFRS IFRS
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue
Oil and gas sales 74,090 - 74,090
Realized gain on hedges 5,884 - 5,884
Royalties (9,173) - (9,173)
----------------------------------------------------------------------------
Petroleum and natural gas
sales, net 70,801 - 70,801
----------------------------------------------------------------------------
Expenses
Operating 4,559 - 4,559
Transportation 1,435 - 1,435
General and administrative (f) 1,836 (290) 1,546
Future performance based
compensation (d) 2,134 (1,328) 806
Interest 4,412 - 4,412
Accretion of decommissioning
liability (c) - 178 178
Depletion and depreciation (f) 20,414 (2,668) 17,746
----------------------------------------------------------------------------
34,790 (4,108) 30,682
----------------------------------------------------------------------------
Earnings before taxes 36,011 4,108 40,119
----------------------------------------------------------------------------
Taxes
Deferred income tax (recovery)
expense (e) (863) 353 (509)
----------------------------------------------------------------------------
Earnings for the period 36,874 3,755 40,628
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Other comprehensive income
(loss)
Change in unrealized gain
(loss) on cash flow hedges (e) 37,921 (10,301) 27,620
Realized (gain) loss on cash
flow hedges (5,884) - (5,884)
----------------------------------------------------------------------------
Comprehensive income for the
period 68,911 (6,548) 62,364
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Peyto Exploration &
Development Corp. (unaudited)
(ii) Reconciliation of
earnings and comprehensive Effect of
income for the year ended Notes Canadian Transition to
December 31, 2010 19(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 - 6,955
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 (9,731) 84,453
Gains on divestitures (f) - (2,249) (2,249)
----------------------------------------------------------------------------
179,970 (16,539) 163,431
----------------------------------------------------------------------------
Earnings before taxes 106,051 16,539 122,590
----------------------------------------------------------------------------
Taxes
Deferred income tax (recovery)
expense (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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(ii) 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 an
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 period ended March 31, 2010 and for the year ended December 31, 2010 was
$0.2 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 period ended March 31, 2010 and year ended December 31, 2010 performance
based compensation expense decreased by $1.3 million and $1.7 million 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 reverted 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 19(i)(c).
For the period ended March 31, 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 $2.7 million and $9.7 million
with a corresponding change to property, plant and equipment.
As a result of specific general and administrative recoveries guidance under
IFRS, $0.3 million and $2.9 million have been capitalized for the period ended
March 31, 2010 and year ended December 31, 2010, respectively.
(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 Stephen Chetner
Vice President, Finance and Chief Financial Corporate Secretary
Officer
Directors
Don Gray, Chairman
Rick Braund
Stephen Chetner
Brian Davis
Michael MacBean, Lead Independent Director
Darren Gee
Gregory Fletcher
Scott Robinson
Auditors
Deloitte & Touche LLP
Solicitors
Burnet, Duckworth & Palmer LLP
Bankers
Bank of Montreal
Union Bank, Canada Branch
BNP Paribas (Canada)
Royal Bank of Canada
Canadian Imperial Bank of Commerce
Alberta Treasury Branches
Societe Generale (Canada Branch)
HSBC Bank Canada
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: www.peyto.com
Stock Listing Symbol: PEY.TO
Toronto Stock Exchange
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