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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 | 0.06 | 0.06 | 0.06 | 0.06 | 119,000 | 17:36:43 |
Hot Features
Premium
Peyto Exploration & Development Corp. ("Peyto" or the "Company") (TSX:PEY) is
pleased to report operating and financial results for the fourth quarter and the
2012 fiscal year. Peyto grew production and reserves per share to record levels
in 2012 while delivering a 76% operating margin1 and a 23% profit margin2. An 8%
return on capital and an 8% return on equity were achieved despite historically
low natural gas prices. Highlights for 2012 include:
-- Production per share up 17%. Annual production increased 26% or 17% per
share to 267 MMCFe/d (44,527 boe/d) in 2012 from 213 MMCFe/d (35,465
boe/d) in 2011. Q4 2012 production was also up 26% to 49,754 boe/d.
-- Reserves per share up 15%. Proved Producing ("PP"), Total Proved ("TP")
and Proved plus Probable Additional ("P+P") reserves increased 24%, 23%,
and 22% (15%, 14%, and 13% per share) to 0.9, 1.7, and 2.4 TCFe,
respectively.
-- Reduced cash costs 22%. Royalties, operating costs, transportation, G&A
and interest expense totaled $1.05/MCFe ($6.30/boe) in 2012 down from
$1.35/MCFe ($8.10/boe) in 2011. Industry leading operating costs were
just $0.32/MCFe ($1.92/boe) in 2012.
-- Funds from Operations per share of $2.22. Generated $313 million in
Funds from Operations ("FFO") in 2012, down 6% from $2.36/share in 2011
despite a 27% drop in realized commodity prices.
-- Capital investments up 63%. Invested a record $452 million to build
25,700 boe/d at a cost of $17,600/boe/d and invested $166 million to
acquire Open Range Energy Corp. ("Open Range"), which produced 4,300
boe/d at year end, for a cost of $38,600/boe/d. Average cost to add new
production was $20,600/boe/d.
-- P+P FD&A half the field netback. All in FD&A cost for PP, TP and P+P
reserves was $2.22/MCFe, $2.04/MCFe and $1.68/MCFe ($10.07/boe),
respectively including changes in Future Development Capital ("FDC"),
while the average field netback was $3.46/MCFe ($20.75/boe).
-- NAV per share of $34. Net Asset Value or the Net Present Value per
share, debt adjusted (discounted at 5%) of the P+P reserves was
$20/share of developed reserves and $14/share of undeveloped reserves.
-- Earnings of $0.67/share and dividends of $0.72/share. A total of $94
million in earnings were generated and $102 million in dividends were
paid to shareholders. Cumulative dividend/distribution payments made by
Peyto to date total $1.3 Billion ($12.31/share).
2012 in Review
The year 2012 was an historic year for Peyto. With the largest capital program
in the Company's history, coupled with its first major corporate acquisition,
Peyto added a record 30,000 boe/d of new production. Peyto again led the
industry as the lowest cost producer and with this advantage was able to
generate a 23% profit margin despite natural gas prices that dropped to their
lowest level in Company history. In addition to growing production and reserves
per share, Peyto increased its ownership and control of processing
infrastructure by 100 mmcf/d or 30%, ensuring this low cost advantage can
continue in the future. Peyto's land position in the Alberta Deep Basin also
grew by more than 30% resulting in the addition of 1.6 new booked horizontal
drilling locations for every well drilled in 2012. Production revenues were
maximized with the installation of Peyto's enhanced NGL extraction facilities at
the Company's Oldman gas plant. Peyto's profitable, returns driven strategy once
again delivered an attractive total return on shareholder's capital in 2012.
(1) Operating Margin is defined as Funds from Operations divided by Revenue
before Royalties but including realized hedging gains (losses).
(2) Profit Margin is defined as Net Earnings for the year divided by Revenue
before Royalties but including realized hedging gains (losses).
Natural gas volumes recorded in thousand cubic feet (mcf) are converted to
barrels of oil equivalent (boe) using the ratio of six (6) thousand cubic
feet to one (1) barrel of oil (bbl). Natural gas liquids and oil volumes in
barrel of oil (bbl) are converted to thousand cubic feet equivalent (mcfe)
using a ratio of one (1) barrel of oil to six (6) thousand cubic feet. This
could be misleading if used in isolation as it is based on an energy
equivalency conversion method primarily applied at the burner tip and does
not represent a value equivalency at the wellhead.
----------------------------------------------------------------------------
3 Months Ended December 31 %
2012 2011 Change
----------------------------------------------------------------------------
Operations
Production
Natural gas (mcf/d) 266,808 212,715 25%
Oil & NGLs (bbl/d) 5,286 3,947 34%
Thousand cubic feet equivalent
(mcfe/d @ 1:6) 298,522 236,394 26%
Barrels of oil equivalent (boe/d @
6:1) 49,754 39,399 26%
Product prices
Natural gas ($/mcf) 3.45 4.21 (18)%
Oil & NGLs ($/bbl) 73.01 88.04 (17)%
Operating expenses ($/mcfe) 0.31 0.35 (11)%
Transportation ($/mcfe) 0.11 0.12 (8)%
Field netback ($/mcfe) 3.62 4.32 (16)%
General & administrative expenses
($/mcfe) 0.02 0.05 (60)%
Interest expense ($/mcfe) 0.32 0.35 (9)%
Financial ($000, except per share)
Revenue 120,310 114,263 5%
Royalties 9,205 9,870 (7)%
Funds from operations 93,948 80,410 17%
Funds from operations per share 0.65 0.60 8%
Total dividends 26,178 24,245 8%
Total dividends per share 0.18 0.18 -
Payout ratio (%) 28 30 (7)%
Earnings 25,823 26,036 (1)%
Earnings per share 0.18 0.19 (5)%
Capital expenditures 156,847 94,688 66%
Weighted average shares outstanding 145,449,651 133,913,301 9%
As at December 31
Net debt (before future compensation
expense and unrealized hedging gains)
Shareholders' equity
Total assets
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
12 Months Ended December 31 %
2012 2011 Change
----------------------------------------------------------------------------
Operations
Production
Natural gas (mcf/d) 238,490 189,653 26%
Oil & NGLs (bbl/d) 4,778 3,856 24%
Thousand cubic feet equivalent
(mcfe/d @ 1:6) 267,160 212,789 26%
Barrels of oil equivalent (boe/d @
6:1) 44,527 35,465 26%
Product prices
Natural gas ($/mcf) 3.23 4.47 (28)%
Oil & NGLs ($/bbl) 73.92 81.67 (9)%
Operating expenses ($/mcfe) 0.32 0.35 (9)%
Transportation ($/mcfe) 0.12 0.13 (8)%
Field netback ($/mcfe) 3.46 4.46 (22)%
General & administrative expenses
($/mcfe) 0.04 0.06 (33)%
Interest expense ($/mcfe) 0.13 0.28 (54)%
Financial ($000, except per share)
Revenue 411,400 424,560 (3)%
Royalties 30,754 41,064 (25)%
Funds from operations 313,243 314,622 -
Funds from operations per share 2.22 2.36 (6)%
Total dividends 101,593 96,068 6%
Total dividends per share 0.72 0.72 -
Payout ratio (%) 33 31 6%
Earnings 93,951 128,183 (27)%
Earnings per share 0.67 0.96 (30)%
Capital expenditures 617,985 379,061 63%
Weighted average shares outstanding 141,093,829 133,196,301 6%
As at December 31
Net debt (before future compensation
expense and unrealized hedging gains) 662,461 465,391 42%
Shareholders' equity 1,210,067 1,015,708 19%
Total assets 2,203,524 1,800,252 22%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
3 Months Ended 12 Months Ended
December 31 December 31
($000) 2012 2011 2012 2011
----------------------------------------------------------------------------
Cash flows from operating
activities 78,878 85,592 284,309 289,995
Change in non-cash working capital 4,457 (19,139) 12,920 3,085
Change in provision for
performance based compensation (7,712) (8,739) (2,819) (1,154)
Gain on disposition of assets 3,870 - 4,378 -
Income tax paid on account of
2003 reassessment 1,868 - 1,868 -
Performance based compensation 12,587 22,696 12,587 22,696
----------------------------------------------------------------------------
Funds from operations 93,948 80,410 313,243 314,622
----------------------------------------------------------------------------
Funds from operations per share 0.65 0.60 2.36 2.36
----------------------------------------------------------------------------
(1) Funds from operations - Management uses funds from operations to analyze
the operating performance of its energy assets. In order to facilitate
comparative analysis, funds from operations is defined throughout this
report as earnings before performance based compensation, non-cash and
non-recurring expenses. Management believes that funds from operations
is an important parameter to measure the value of an asset when combined
with reserve life. Funds from operations is not a measure recognized by
Canadian generally accepted accounting principles ("GAAP") and does not
have a standardized meaning prescribed by GAAP. Therefore, funds from
operations, as defined by Peyto, may not be comparable to similar
measures presented by other issuers, and investors are cautioned that
funds from operations should not be construed as an alternative to net
earnings, cash flow from operating activities or other measures of
financial performance calculated in accordance with GAAP. Funds from
operations cannot be assured and future dividends may vary.
The Peyto Strategy
The Peyto strategy has long been one of building enduring shareholder value by
focusing on generating the maximum possible returns on invested capital. This
disciplined model has been tested during times of high commodity prices and
record industry activity levels as well as low commodity prices and low activity
levels. As with any commodity business, a focus on keeping costs low at all
times yields significant advantages over the competition and contributes to
generating the best return on the capital invested. Peyto has successfully
executed this strategy, aggressively investing capital during opportunistic
periods in the cycle while at other times restricting investment, but at all
times focusing on cost control. In total, over $2.9 billion has been invested in
developing producing reserves that to date have sold for over 1.75 times the
total average cost to develop and produce them. The following table illustrates
the profitability of the Peyto strategy with the average sales price far
exceeding Peyto's historic costs of development and production.
----------------------------------------------------------------------------
($/Mcfe) 2002 2003 2004 2005 2006 2007
----------------------------------------------------------------------------
Sales Price $4.78 $7.21 $7.32 $8.87 $8.76 $8.93
----------------------------------------------------------------------------
Cost to develop(1) ($0.84) ($1.33) ($1.60) ($2.39) ($2.95) ($2.11)
Cost to produce(2) ($1.59) ($2.16) ($2.21) ($2.76) ($2.66) ($2.75)
----------------------------------------------------------------------------
"Profit" $2.35 $3.72 $3.51 $3.72 $3.15 $4.07
Payout $1.36 $2.28 $2.81 $3.47 $3.92
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($/Mcfe) 2008 2009 2010 2011 2012
----------------------------------------------------------------------------
Sales Price $9.54 $6.75 $6.15 $5.47 $4.21
----------------------------------------------------------------------------
Cost to develop(1) ($2.88) ($2.26) ($2.10) ($2.12) ($2.22)
Cost to produce(2) ($3.01) ($1.75) ($1.63) ($1.35) ($1.05)
----------------------------------------------------------------------------
"Profit" $3.65 $2.74 $2.42 $2.00 $0.94
Payout $4.25 $4.03 $3.37 $1.24 $1.04
----------------------------------------------------------------------------
(1) Cost to develop is the PDP FD&A
(2) Cost to produce is the total cash costs including Royalties, Operating
costs, Transportation, G&A and Interest.
(3) Payout is the annual distribution or dividend in $/mcfe of production.
In total, over $1.3 billion in profit has been returned to shareholders. As
illustrated above, these payments have come from the ongoing profitable
development and production of reserves. The success and sustainability of the
Peyto strategy continues to be evident.
Capital Expenditures
Peyto deployed a record amount of capital in 2012, with an exploration and
development program comprising $452 million and a corporate acquisition costing
$166 million, after associated dispositions.
The 2012 exploration and development program was 19% larger than the 2011
program making it the largest in the Company's 14 year history. In total, $338
million was invested into the drilling and completion of 86 gross (76 net)
horizontal wells, while $47 million was invested into pipelines and wellsite
equipment to bring those wells on production. An additional $11 million was
invested into expanding Peyto's natural gas processing capacity while $26
million was invested in the Oldman plant enhanced liquids extraction facility.
Peyto spent $29 million adding to its extensive inventory of profitable, high
quality drilling locations with a minor property acquisition in the Sundance
area and the successful purchase of 72 new sections of crown land at an average
price of $232/acre.
On August 14, 2012, Peyto closed the acquisition of Open Range for an effective
total capital cost of $187.2 million. The acquisition was conducted pursuant to
a plan of arrangement with Peyto exchanging 0.0723 Peyto shares for each Open
Range share (5.4 million Peyto shares total) and assuming $75 million in net
debt (inclusive of transaction costs). On December 1, 2012, Peyto disposed of
some minor non-core Open Range assets in the Waskahigan area for total proceeds
of $20.9 million, which effectively reduced the cost of the acquisition to
$166.3 million.
The following table summarizes the increased capital expenditures for the fourth
quarter and 2012 year.
----------------------------------------------------------------------------
Three Months Twelve Months
ended Dec. 31 ended Dec. 31
($000) 2012 2011 2012 2011
----------------------------------------------------------------------------
Land 5,206 5,910 10,770 21,002
Seismic 612 1,245 1,741 2,859
Drilling - Exploratory & Development 123,778 77,570 337,988 279,446
Production Equipment, Facilities &
Pipelines 48,015 10,644 84,482 72,079
Acquisition of Open Range Energy Corp. - - 187,187 -
Property Acquisitions 75 527 17,841 5,581
Dispositions (16,969) (1,208) (17,646) (1,906)
(Gains) Losses on Dispositions (3,870) (1,126) (4,378) (1,634)
----------------------------------------------------------------------------
Total Capital Expenditures 156,847 93,562 617,985 377,427
----------------------------------------------------------------------------
Reserves
Peyto was successful growing reserves and values in all categories in 2012. The
following table illustrates the change in reserve volumes and Net Present Value
("NPV") of future cash flows, discounted at 5%, before income tax and using
forecast pricing.
----------------------------------------------------------------------------
As at December 31 % Change, debt
2012 2011 % Change adjusted per share(i)
----------------------------------------------------------------------------
Reserves (BCFe)
Proved Producing 945 765 24% 10%
Total Proved 1,659 1,352 23% 9%
Proved + Probable
Additional 2,353 1,935 22% 8%
Net Present Value
($millions) Discounted
at 5%
Proved Producing $2,806 $2,624 7% -8%
Total Proved $4,166 $3,972 5% -7%
Proved + Probable
Additional $5,732 $5,484 5% -6%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(i) Per share reserves are adjusted for changes in net debt by converting
debt to equity using the Dec 31 share price of $22.99 for 2012 and share
price of $24.39 for 2011. Net Present Values are adjusted for debt by
subtracting net debt from the value prior to calculating per share
amounts.
Note: based on the InSite Petroleum Consultants ("InSite") report effective
December 31, 2012. The InSite price forecast is available at
www.InSitepc.com. For more information on Peyto's reserves, refer to the
Press Releases dated February 13, 2013 and February 14, 2013 announcing the
2012 Year End Reserve Report which is available on the website at
www.peyto.com. The complete statement of reserves data and required
reporting in compliance with NI 51-101 will be included in Peyto's Annual
Information Form to be released in March 2013.
Performance Ratios
The following table highlights additional annual performance indicators, to be
used for comparative purposes, but it is cautioned that in isolation they do not
measure investment success.
----------------------------------------------------------------------------
2012 2011 2010 2009 2008 2007
----------------------------------------------------------------------------
Proved Producing
FD&A ($/mcfe) $2.22 $2.12 $2.10 $2.26 $2.88 $2.11
RLI (yrs) 9 9 11 14 14 13
Recycle Ratio 1.6 1.9 2.0 1.8 2.3 2.8
Reserve Replacement 284% 230% 239% 79% 110% 127%
----------------------------------------------------------------------------
Total Proved
FD&A ($/mcfe) $2.04 $2.13 $2.35 $1.73 $3.17 $1.57
RLI (yrs) 15 16 17 21 17 16
Recycle Ratio 1.7 1.9 1.8 2.3 2.1 3.7
------------------------------------ -------- --------
Reserve Replacement 414% 452% 456% 422% 139% 175%
Future Development Capital
($MM) $1,318 $1,111 $741 $446 $222 $169
----------------------------------------------------------------------------
Proved plus Probable
Additional
FD&A ($/mcfe) $1.68 $1.90 $2.19 $1.47 $3.88 $1.56
RLI (yrs) 22 22 25 29 23 21
Recycle Ratio 2.1 2.1 1.9 2.8 1.7 3.7
Reserve Replacement 527% 585% 790% 597% 122% 117%
Future Development Capital
($MM) $2,041 $1,794 $1,310 $672 $390 $321
----------------------------------------------------------------------------
-- FD&A (finding, development and acquisition) costs are used as a measure
of capital efficiency and are calculated by dividing the capital costs
for the period, including the change in undiscounted future development
capital ("FDC"), by the change in the reserves, incorporating revisions
and production, for the same period (eg. Total Proved
($618+$207)/(1,659-1,352+98) = $2.04/mcfe or $12.24/boe).
-- The reserve life index (RLI) is calculated by dividing the reserves (in
boes) in each category by the annualized average production rate in
boe/year (eg. Proved Producing 157,491/(49.754x365) = 8.7). Peyto
believes that the most accurate way to evaluate the current reserve life
is by dividing the proved developed producing reserves by the actual
fourth quarter average production. In Peyto's opinion, for comparative
purposes, the proved developed producing reserve life provides the best
measure of sustainability.
-- The Recycle Ratio is calculated by dividing the field netback per MCFe,
before hedging, by the FD&A costs for the period (eg. Proved Producing
(($3.46)/$2.22=1.6). The recycle ratio is comparing the netback from
existing reserves to the cost of finding new reserves and may not
accurately indicate investment success unless the replacement reserves
are of equivalent quality as the produced reserves.
-- The reserve replacement ratio is determined by dividing the yearly
change in reserves before production by the actual annual production for
the year (eg. Total Proved ((1,659-1,352+98)/98) = 4.14).
Value Creation/Reconciliation
In order to measure the success of all of the capital invested in 2012, it is
necessary to quantify the total amount of value added during the year and
compare that to the total amount of capital invested. As requested, Insite has
run last year's reserve evaluation with this year's price forecast to remove the
change in value attributable to both commodity prices and changing royalties.
This approach isolates the value created by the Peyto team from the value
created (or lost) by those changes outside of their control. Since the capital
investments in 2012 were funded from a combination of cash flow, debt and
equity, it is necessary to include the change in debt and the change in shares
outstanding to determine if the change in value is truly accretive to
shareholders.
At year end 2012, Peyto's estimated net debt had increased by $196.8 million to
$662.4 million while the number of shares outstanding had increased by 10.3
million shares to 148.7 million shares. The change in debt includes all of the
capital expenditures, as well as acquisitions, and the total fixed and
performance based compensation paid out during the year.
Based on this reconciliation of changes in BT NPV, the Peyto team was able to
create $963 million of Proved Producing, $1.36 billion of Total Proved, and $2.0
billion of Proved plus Probable Additional undiscounted reserve value, with a
$618 million capital investment. The ratio of value creation to capital
expenditure is what Peyto refers to as the NPV recycle ratio, which is simply
the undiscounted value addition, resulting from the capital program, divided by
the capital investment. For 2012, the Proved Producing NPV recycle ratio is 1.6.
Refer to the value reconciliation table in the February 14, 2013 Reserve Press
Release for additional details on the value creation determination.
Performance Measures
There are a number of performance measures that are used in the oil and gas
industry in an attempt to evaluate how profitably capital has been invested.
Peyto believes that the value analysis and reconciliation presented above is the
best determination of profitability as it compares the value of what was created
relative to what was invested. This is because the NPV of an oil and gas asset
takes into consideration the reserves, the production forecast, the future
royalties and operating costs, future capital and the current commodity price
outlook. In 2012, the Proved Producing NPV recycle ratio was 1.6 times. This
means for each dollar invested, the Peyto team was able to create 1.6 new
dollars of Proved Producing reserve value. The average NPV Recycle Ratio over
the last 5 years is 3.0 times for undiscounted future values or 2.2 times for
future values discounted at 10%. The historic NPV recycle ratios are presented
in the following table.
----------------------------------------------------------------------------
Dec 31, Dec 31, Dec 31, Dec 31, Dec 31, Dec 31, Dec 31,
Value Creation 2012 2011 2010 2009 2008 2007 2006
----------------------------------------------------------------------------
NPV(0) Recycle
Ratio
Proved
Producing 1.6 2.4 3.5 5.4 2.1 4.7 2.9
Total Proved 2.2 4.7 6.1 18.9 2.5 5.5 2.9
Proved +
Probable
Additional 3.2 6.6 10.3 27.1 2.2 3.8 3.8
----------------------------------------------------------------------------
-- NPV(0) (net present value) recycle ratio is calculated by dividing the
undiscounted NPV of reserves added in the year by the total capital cost
for the period (eg. Proved Producing ($963/$618) = 1.6).
Quarterly Review
Activity in the fourth quarter of 2012 included the drilling of 28 gross (27.2
net) horizontal wells, the completion of 33 gross (29.6 net) wells and the
installation of wellsite equipment and tie in of 34 gross (30.4 net) wells.
Capital expenditures in Q4 totaled $156.8 million with $78 million spent on
drilling, $47 million on completions, and $22 million on wellsite equipment and
pipelines. Installation of the enhanced liquids extraction facilities at the
Oldman gas plant was responsible for the majority of the $25 million invested in
facilities. In the quarter, 30.5 sections of new land was purchased at crown
land sales for $5.2 million or $267/ac.
On December 1, 2012 Peyto disposed of some minor non-core Open Range assets in
the Waskahigan area for total proceeds of $20.9 million reflected in the
previous capital summary as a disposition and gain on disposition.
Production for Q4 2012 was up 26% from Q4 2011 to 49,754 boe/d including 299
mmcf/d of natural gas and 5,286 bbl/d of oil and natural gas liquids. Fourth
quarter production was less than expected, however, due to an unanticipated
outage at Peyto's Oldman gas processing facility. The cause of the outage was a
faulty piece of equipment installed during the new Oldman Deep Cut plant
expansion. The defective equipment prevented the operation of approximately two
thirds, or 80 mmcf/d, of the processing capacity at the facility. This equipment
has been repaired and the impacted processing capacity was brought back online
on January 7, 2013 with the Deep Cut plant operation commencing January 25,
2013. Approximately 10,700 boe/d of net production was offline for the final 13
days in December.
Peyto's natural gas price in the fourth quarter 2012 of $3.45/mcf was 18% lower
than the previous year, while the realized oil and natural gas liquids price of
$73.01/bbl was 17% lower. These prices combined for a realized price of
$4.38/mcfe including $0.13/mcfe of realized hedging gain. Q4 2012 total cash
costs of $1.10/mcfe included $0.34/mcfe for royalties, $0.31/mcfe for operating
costs, $0.11/mcfe for transportation, $0.02/mcfe for G&A and $0.32/mcfe for
interest. Realized prices less cash costs resulted in cash netbacks for the
quarter of $3.28/mcfe or a 75% operating margin.
Peyto incurred a one-time tax charge of $1.9 million or $0.12/mcfe in the
quarter due to the reassessment of Peyto's 2003 Alberta income tax return. The
reassessment related to the treatment of the payout of stock options for income
tax purposes upon conversion to an income trust in 2003. The federal
reassessment was paid to Canada Revenue Agency in 2008, however, the Alberta
Government subsequently reassessed the 2003 Alberta income tax return in
January, 2013 which was paid in the same month and accrued as a one-time charge
in the 2012 financial results.
Marketing
The current natural gas price outlook is substantially better than this time
last year. Although storage volumes are at the high end of historical levels,
growing demand and flat to declining North American natural gas supply is
supporting prices at $3.00/GJ CND$ and $3.50/MMBTU US$. With current supplies
matching demand, weather should continue to play a significant role in future
prices. In addition, natural gas is playing an increasing role for summer power
generation, particularly in light of the current projections for decreased hydro
power this coming spring and ongoing retirement of coal fired power plants.
Natural gas liquids prices have, in general, remained substantially higher than
the equivalent price in gaseous form. Recent industry trends to extract more
Propane and Ethane from the natural gas production have increase supplies and
filled available liquefied petroleum gas ("LPG") fractionation plant capacity.
This has put significant downward pressure on the price for these specific
products which will likely continue for the near future. The majority of Peyto's
LPG is under long term contract for transportation and fractionation.
Approximately 50% of Peyto's natural gas production in the fourth quarter had
been pre-sold in forward sales done over the previous year at an average price
of $3.17/GJ. The remaining balance of production was subject to AECO monthly
spot prices that averaged $2.90/GJ. On a blended basis, Peyto's realized gas
price was $3.04/GJ or $3.45/mcf, reflective of Peyto's high heat content natural
gas production.
The Company's hedging practice of layering in future sales in the form of fixed
price swaps, in order to smooth out the volatility in natural gas price,
continued throughout the quarter and into 2013. The following table summarizes
the remaining hedged volumes and prices for the upcoming years, effective March
6, 2013:
----------------------------------------------------------------------------
Future Sales Average Price (CAD)
----------------------------------------------------------------------------
GJ Mcf $/GJ $/Mcf
----------------------------------------------------------------------------
2013 54,842,500 46,873,932 $3.20 $3.74
2014 27,575,000 23,568,376 $3.24 $3.79
----------------------------------------------------------------------------
Total 82,417,500 70,442,308 $3.21 $3.76
----------------------------------------------------------------------------
As illustrated in the following table, Peyto's annual realized natural gas
liquids prices(1) were approximately 10% lower on a year over year basis, due
primarily to realized Propane prices which were 45% lower than the price
realized in 2011.
----------------------------------------------------------------------------
Three Months ended Dec. 31 Twelve Months ended Dec. 31
2012 2011 2012 2011
----------------------------------------------------------------------------
Condensate ($/bbl) 91.22 101.08 94.78 94.47
Propane ($/bbl) 25.58 46.03 24.12 44.00
Butane ($/bbl) 63.38 67.46 64.05 63.41
Pentane ($/bbl) 94.34 104.03 98.93 96.63
----------------------------------------------------------------------------
(1) Liquids prices are Peyto realized prices in Canadian dollars adjusted
for fractionation and transportation.
Peyto's hedging practice with respect to propane and butane also continued
throughout the fourth quarter. The following table summarizes the hedged volumes
and prices for the upcoming years, effective March 6, 2013.
----------------------------------------------------------------------------
Propane Butane
----------------------------------------------------------------------------
Future Sales Average Price Future Sales Average Price
(bbls) ($USD/bbl) (bbls) ($USD/bbl)
----------------------------------------------------------------------------
2013 213,972 $33.95 15,345 $65.88
----------------------------------------------------------------------------
Activity Update
Peyto has continued its record level of activity into the first quarter of 2013.
Nine rigs are drilling and four completions crews are following behind the
drilling rigs. To the end of February, 17 gross (16.9 net) wells have been rig
released and 14 gross (13.2 net) wells have been brought on production.
Current production is approximately 57,000 boe/d which includes 4,300 boe/d of
new additions since early January. Over 5,000 boe/d of production awaits tie-in
of 8.0 net wells that have been completed but are not yet onstream.
Over the first two months of 2013, two compressor expansion projects were
completed. An additional 10 MMcf/d of compression was added to the Nosehill
Plant taking the facility capacity to 120 MMcf/d. In addition, another 10 MMcf/d
of compression was added to the Wildhay Plant taking it to a capacity of 70
MMcf/d.
Three plant construction projects are in the early stage of equipment
fabrication with field work anticipated for the summer of 2013 and start-ups
ranging from late summer to fall. The first project is a 30 MMcf/d addition to
the Swanson Plant (taking it to 60 MMcf/d) for the accommodation of Ansell area
growth volumes. In addition to the plant expansion, a 50 km strategic pipeline
from Ansell to Swanson is currently under construction with targeted completion
after breakup. The second project is a new Oldman North Plant to be located
adjacent to the existing 125 MMcf/d Oldman Plant and initially designed for 40
MMcf/d. This plant will handle ongoing Cardium and Falher horizontal well
development. A third new facility is planned for mid-fall for a new step-out
area of Wilrich development that is presently undergoing early stage delineation
drilling.
The Oldman Deep Cut facility built at the end of 2012 was successfully brought
online in mid-January. The plant is currently running just below its 80 MMcfd
raw gas capacity as some final re-compression tuning occurs for the four new
compressors. The overall Oldman LPG recovery level has increased from a pre-Deep
Cut level of 1,600 bbl/d to a present level of 2,400 bbl/d at the current -75
degrees C operating level for the Deep Cut train. With continued tuning of the
re-compression, throughput will be brought up and chilling will be dropped
towards the -80 degrees C design level to realize the full 2,600 bbl/d of LPG.
As in most past years, Peyto tentatively plans to shut down its drilling
operations over spring break-up which is contemplated to occur from early April
to mid-May and resume its drilling program with nine rigs. Post break-up
drilling will focus in the traditional Greater Sundance area with volumes
filling the new Oldman North Plant, the Ansell area with volumes pipelined to
the expanded Swanson Plant, and with some additional Northern Cardium drilling.
The $450 to $500 million capital program is on pace and it is expected that
target 2013 exit production levels of 62,000 to 67,000 boe/d will be reached.
2013 Outlook
2013 is forecast to be the most active in the Company's history. It also comes
at a time when the majority of natural gas producers in North America are
challenged by low natural gas prices and high costs, rendering many plays
uneconomic. Over its history, Peyto has maintained a unique low cost advantage
that allows the Company to profitably grow its asset base, despite lower
commodity prices, taking advantage of lower service and material costs. In
effect, Peyto can be "greedy when others are fearful" and capture new
opportunities when others are cutting capital budgets and rationalizing assets.
This prevailing economic condition is forecast to continue throughout 2013
allowing Peyto the opportunity to deliver the same superior total returns to
shareholders as in the past. Peyto's expertise in the Alberta Deep Basin will
serve it well in this regard. The company's financial flexibility, quality asset
base and strong balance sheet position Peyto to continue to be opportunistic. As
always, capital investments will only be pursued if Peyto's high return
objectives can be met.
Conference Call and Webcast
A conference call will be held with the senior management of Peyto to answer
questions with respect to the 2012 fourth quarter and full year financial
results on Thursday, March 7th, 2013, at 9:00 a.m. Mountain Standard Time (MST),
or 11:00 a.m. Eastern Standard Time (EST). To participate, please call
1-416-340-8530 (Toronto area) or 1-877-440-9795 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 9284446.
The replay will be available at 11:00 a.m. MST, 1:00 p.m. EST Thursday, March
7th, 2013 until midnight EDT on Thursday, March 14th, 2013. The conference call
can also be accessed through the internet at
http://events.digitalmedia.telus.com/peyto/030713/index.php. After this time the
conference call will be archived on the Peyto Exploration & Development website
at www.peyto.com.
Management's Discussion and Analysis
A copy of the fourth quarter report to shareholders, including the MD&A, and
audited financial statements and related notes is available at
http://www.peyto.com/news/Q42012MDandA.pdf and will be filed at SEDAR,
www.sedar.com, at a later date.
Annual General Meeting
Peyto's Annual General Meeting of Shareholders is scheduled for 3:00 p.m. on
Wednesday, June 5, 2013 at Livingston Place Conference Centre, +15 level,
222-3rd Avenue SW, Calgary, Alberta. Shareholders are encouraged to visit the
Peyto website at www.peyto.com where there is a wealth of information designed
to inform and educate investors. A monthly President's Report can also be found
on the website which follows the progress of the capital program and the ensuing
production growth, along with video and audio commentary from Peyto's senior
management.
Darren Gee, President and CEO
March 6, 2013
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. In particular, but without
limiting the foregoing, this news release contains forward-looking information
and statements pertaining to the following: the timing of its enhanced liquids
extraction project and guidance as to the capital expenditure plans of Peyto
under the heading "2013 Outlook". By their nature, forward-looking statements
are subject to numerous risks and uncertainties, some of which are beyond these
parties' control, including the impact of general economic conditions, industry
conditions, volatility of commodity prices, currency fluctuations, imprecision
of reserve estimates, environmental risks, competition from other industry
participants, the lack of availability of qualified personnel or management,
stock market volatility and ability to access sufficient capital from internal
and external sources. Readers are cautioned that the assumptions used in the
preparation of such information, although considered reasonable at the time of
preparation, may prove to be imprecise and, as such, undue reliance should not
be placed on forward-looking statements. Peyto's actual results, performance or
achievement could differ materially from those expressed in, or implied by,
these forward-looking statements and, accordingly, no assurance can be given
that any of the events anticipated by the forward-looking statements will
transpire or occur, or if any of them do so, what benefits Peyto will derive
therefrom.
Peyto Exploration & Development Corp.
Consolidated Balance Sheet
(Amount in $ thousands)
December 31 December 31
2012 2011
----------------------------------------------------------------------------
Assets
Current assets
Cash - 57,224
Accounts receivable 85,677 53,829
Due from private placement (Note 7) 3,459 9,740
Derivative financial instruments (Note 13) 10,254 38,530
Prepaid expenses 4,150 3,991
----------------------------------------------------------------------------
103,540 163,314
----------------------------------------------------------------------------
Long-term derivative financial instruments (Note
13) - 6,304
Prepaid capital 3,714 1,414
Property, plant and equipment, net (Note 4) 2,096,270 1,629,220
----------------------------------------------------------------------------
2,099,984 1,636,938
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2,203,524 1,800,252
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable and accrued liabilities 164,946 110,483
Current income tax 1,890 -
Dividends payable (Note 7) 8,911 8,278
Provision for future performance based
compensation (Note 11) 2,677 4,321
----------------------------------------------------------------------------
178,424 123,082
----------------------------------------------------------------------------
Long-term debt (Note 5) 580,000 470,000
Long-term derivative financial instruments (Note
13) 2,532 -
Provision for future performance based
compensation (Note 11) 59 1,235
Decommissioning provision (Note 6) 58,201 38,037
Deferred income taxes (Note 12) 174,241 152,190
----------------------------------------------------------------------------
815,033 661,462
----------------------------------------------------------------------------
Shareholders' equity
Shareholders' capital (Note 7) 1,124,382 889,115
Shares to be issued (Note 7) 3,459 9,740
Retained earnings 75,247 82,889
Accumulated other comprehensive income (Note 7) 6,979 33,964
----------------------------------------------------------------------------
1,210,067 1,015,708
----------------------------------------------------------------------------
2,203,524 1,800,252
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Approved by the Board of Directors
Michael MacBean Darren Gee
Director Director
Peyto Exploration & Development Corp.
Consolidated Income Statement
(Amount in $ thousands)
Year ended December 31
2012 2011
----------------------------------------------------------------------------
Revenue
Oil and gas sales 357,734 387,240
Realized gain on hedges (Note 13) 53,667 37,320
Royalties (30,754) (41,064)
----------------------------------------------------------------------------
Petroleum and natural gas sales, net 380,647 383,496
----------------------------------------------------------------------------
Expenses
Operating (Note 8) 31,260 27,379
Transportation 11,275 9,754
General and administrative (Note 9) 3,846 4,911
Market and reserves based bonus (Note 11) 12,587 22,696
Future performance based compensation (Note 11) (2,819) (1,154)
Interest (Note 10) 25,401 21,881
Accretion of decommissioning provision (Note 10) 1,044 840
Depletion and depreciation (Note 4) 172,338 130,678
Gain on disposition of assets (Note 4) (4,378) (1,634)
----------------------------------------------------------------------------
250,554 215,351
----------------------------------------------------------------------------
Earnings before taxes 130,093 168,145
----------------------------------------------------------------------------
Income tax
Deferred income tax expense (recovery) (Note 12) 34,274 35,013
Income tax expense (Note 12) 1,868 4,949
----------------------------------------------------------------------------
Earnings for the year 93,951 128,183
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Earnings per share (Note 7)
Basic and diluted $ 0.67 $ 0.96
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted average number of common shares
outstanding (Note 7)
Basic and diluted 141,093,829 133,196,103
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Peyto Exploration & Development Corp.
Consolidated Statement of Comprehensive Income
(Amount in $ thousands)
Year ended December 31
2012 2011
----------------------------------------------------------------------------
Earnings for the year 93,951 128,183
Other comprehensive income
Change in unrealized gain (loss) on cash flow hedges 17,687 54,243
Deferred tax recovery (expense) 8,995 (3,852)
Realized gain on cash flow hedges (53,667) (37,320)
----------------------------------------------------------------------------
Comprehensive Income 66,966 141,254
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Peyto Exploration & Development Corp.
Consolidated Statement of Changes in Equity
(Amount in $ thousands)
Year ended December 31
2012 2011
----------------------------------------------------------------------------
Shareholders' capital, Beginning of Year 889,115 755,831
----------------------------------------------------------------------------
Common shares issued 115,024 115,126
Common shares issued pursuant to acquisition of Open
Range Energy Corp. 112,187 -
Common shares issued by private placement 11,952 17,150
Common shares issuance costs (net of tax) (3,896) (3,854)
Common shares issued pursuant to DRIP - 1,973
Common shares issued pursuant to OTUPP - 2,889
----------------------------------------------------------------------------
Shareholders' capital, End of Year 1,124,382 889,115
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Common shares to be issued, Beginning of Year 9,740 17,285
----------------------------------------------------------------------------
Common shares issued (9,740) (17,285)
Common shares to be issued 3,459 9,740
----------------------------------------------------------------------------
Common shares to be issued, End of Year 3,459 9,740
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Retained earnings, Beginning of Year 82,889 50,774
----------------------------------------------------------------------------
Earnings for the year 93,951 128,183
Dividends (Note 7) (101,593) (96,068)
----------------------------------------------------------------------------
Retained earnings, End of Year 75,247 82,889
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated other comprehensive income, Beginning of
Year 33,964 20,893
----------------------------------------------------------------------------
Other comprehensive income (loss) (26,985) 13,071
----------------------------------------------------------------------------
Accumulated other comprehensive income, End of Year 6,979 33,964
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Shareholders' Equity 1,210,067 1,015,708
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Peyto Exploration & Development Corp.
Consolidated Statement of Cash Flows
(Amount in $ thousands)
Year ended December 31
2012 2011
----------------------------------------------------------------------------
Cash provided by (used in)
Operating activities
Earnings 93,951 128,183
Items not requiring cash:
Deferred income tax 34,274 35,013
Gain on disposition of assets (4,378) (1,634)
Depletion and depreciation 172,338 130,678
Accretion of decommissioning provision 1,044 840
Change in non-cash working capital related to
operating activities (12,920) (3,085)
----------------------------------------------------------------------------
284,309 289,995
----------------------------------------------------------------------------
Financing activities
Issuance of common shares 126,976 132,276
Issuance costs (5,195) (5,137)
Dividends (100,960) (103,615)
Increase (decrease) in bank debt (40,000) 115,000
Repayment of Open Range bank debt (72,000) -
Issuance of long term notes 150,000 -
----------------------------------------------------------------------------
58,821 138,524
----------------------------------------------------------------------------
Investing activities
Additions to property, plant and equipment (400,354) (382,189)
Dispositions of property, plant and equipment - 3,000
----------------------------------------------------------------------------
(400,354) (379,189)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net increase in cash (57,224) 49,330
Cash, beginning of year 57,224 7,894
----------------------------------------------------------------------------
Cash, end of year - 57,224
----------------------------------------------------------------------------
The following amounts are included in Cash flows from operating activities:
----------------------------------------------------------------------------
Cash interest paid 23,460 19,656
Cash taxes paid - -
----------------------------------------------------------------------------
.
Peyto Exploration & Development Corp.
Notes to Consolidated Financial Statements
As at December 31, 2012 and 2011
(Amount in $ thousands, except as otherwise noted)
1. Nature of operations
Peyto Exploration & Development Corp. and its wholly owned subsidiary Open Range
Energy Corp. ("Open Range"), (collectively "Peyto" or the "Company") are Calgary
based oil and natural gas companies. Peyto and Open Range amalgamated on January
1, 2013. Peyto conducts exploration, development and production activities in
Canada. Peyto is incorporated and domiciled in the Province of Alberta, Canada.
The address of its registered office is 1500, 250 - 2nd Street SW, Calgary,
Alberta, Canada, T2P 0C1.
These financial statements were approved and authorized for issuance by the
Board of Directors of Peyto on March 5, 2013.
2. Basis of presentation
These consolidated financial statements ("financial statements") for the years
ended December 31, 2012 and December 31, 2011 represent the Company's results
and financial position in accordance with International Financial Reporting
Standards ("IFRS"). The consolidated financial statements include the accounts
of Peyto Exploration & Development Corp. and its subsidiary. Subsidiaries are
defined as any entities, including unincorporated entities such as partnerships,
for which the Company has the power to govern their financial and operating
policies to obtain benefits from their activities. Intercompany balances, net
earnings and unrealized gains and losses arising from intercompany transactions
are eliminated in preparing the consolidated financial statements.
a) Summary of significant accounting policies
The precise determination of many assets and liabilities is dependent upon
future events and the preparation of periodic financial statements necessarily
involves the use of estimates and approximations. Accordingly, actual results
could differ from those estimates. The financial statements have, in
management's opinion, been properly prepared within reasonable limits of
materiality and within the framework of the Company's basis of presentation as
disclosed.
b) Significant accounting estimates and judgements
The timely preparation of the financial statements in conformity with 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 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
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 plus probable 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 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 operates 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) Cash Equivalents
Cash equivalents include term deposits or a similar type of instrument, with a
maturity of three months or less when purchased.
e) 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 asset'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.
f) 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
assets.
g) Property, plant and equipment
Oil and gas properties and other property, plant and equipment are 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 as 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 amount.
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 reservoir 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 useful life of 20 years.
h) 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.
i) 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 asset or 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 securities 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.
j) 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.
k) 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 balance sheet. The Company has classified each financial instrument into the
following categories: "fair value through profit or loss"; "loans &
receivables"; and "other liabilities". Subsequent measurement of the financial
instruments is based on their classification. Unrealized gains and losses on
fair value through profit or loss financial instruments are recognized in
earnings. The other categories of financial instruments are recognized at
amortized cost using the effective interest rate method. The Company has made
the following classifications:
----------------------------------------------------------------------------
Financial Assets & Liabilities Category
----------------------------------------------------------------------------
Cash Fair value through profit or loss
----------------------------------------------------------------------------
Accounts Receivable Loans & receivables
----------------------------------------------------------------------------
Due from Private Placement Loans & receivables
----------------------------------------------------------------------------
Accounts Payable and Accrued Liabilities Other liabilities
----------------------------------------------------------------------------
Provision for Future Performance Based Other liabilities
Compensation
----------------------------------------------------------------------------
Dividends Payable Other liabilities
----------------------------------------------------------------------------
Long Term Debt Other liabilities
----------------------------------------------------------------------------
Derivative Financial Instruments Fair value through profit or loss
----------------------------------------------------------------------------
Derivative instruments and risk management
Derivative instruments are utilized by the Company to manage market risk against
volatility in commodity prices. The Company's policy is not to utilize
derivative instruments for speculative purposes. The Company has chosen to
designate its existing derivative instruments as cash flow hedges. The Company
assesses, on an ongoing basis, whether the derivatives that are used as cash
flow hedges are highly effective in offsetting changes in cash flows of hedged
items. All derivative instruments are recorded on the balance sheet at their
fair value. The effective portion of the gains and losses is recorded in other
comprehensive income until the hedged transaction is recognized in earnings.
When the earnings impact of the underlying hedged transaction is recognized in
the income statement, the fair value of the associated cash flow hedge is
reclassified from other comprehensive income into earnings. Any hedge
ineffectiveness is immediately recognized in earnings. The fair values of
forward contracts are based on forward market prices.
Embedded derivatives
An embedded derivative is a component of a contract that causes some of the cash
flows of the combined instrument to vary in a way similar to a stand-alone
derivative. This causes some or all of the cash flows that otherwise would be
required by the contract to be modified according to a specified variable, such
as interest rate, financial instrument price, commodity price, foreign exchange
rate, a credit rating or credit index, or other variables to be treated as a
financial derivative. The Company has no contracts containing embedded
derivatives.
Normal purchase or sale exemption
Contracts that were entered into and continue to be held for the purpose of the
receipt or delivery of a non-financial item in accordance with the Company's
expected purchase, sale or usage requirements fall within the exemption from IAS
32 Financial Instruments: Presentation ("IAS 32") and IAS 39, which is known as
the 'normal purchase or sale exemption'. The Company recognizes such contracts
in its balance sheet only when one of the parties meets its obligation under the
contract to deliver either cash or a non-financial asset.
l) 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 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.
m) 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.
n) 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.
o) 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 income 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 income tax assets are only recognized to the
extent it is probable that sufficient future taxable income will be available to
allow the deferred income tax asset to be realized. Accumulated deferred income
tax balances are adjusted to reflect changes in income tax rates that are
enacted or substantively enacted with the adjustment being recognized in
earnings in the period that the change occurs, except for items recognized in
shareholders' equity.
p) 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 amount of the assets disposed. Gains and losses on
disposition are recognized in earnings in the same period as the transaction
date.
q) 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.
r) 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 the related liability on the balance sheet.
s) 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 instruments
outstanding which would cause a difference between the basic and diluted
earnings per share.
t) Shareholders' 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.
u) Standards issued but not yet effective
Peyto has reviewed new and revised accounting pronouncements that have been
issued but are not yet effective and determined that the following may have an
impact on the Company:
In May 2011, the IASB released the following new standards: IFRS 10,
"Consolidated Financial Statements", IFRS 11, "Joint Arrangements", IFRS 12,
"Disclosures of Interests in Other Entities" and IFRS 13, "Fair Value
Measurement". Each of these standards is to be adopted for fiscal years
beginning January 1, 2013 with earlier adoption permitted. A brief description
of each new standard follows below:
-- IFRS 10, "Consolidated Financial Statements" supercedes IAS 27
"Consolidation and Separate Financial Statements" and SIC-12
"Consolidation - Special Purpose Entities". This standard provides a
single model to be applied in control analysis for all investees
including special purpose entities. The adoption of this standard is not
expected to have any impact on Peyto's financial statements.
-- IFRS 11, "Joint Arrangements" divides joint arrangements into two types,
joint operations and joint ventures, each with their own accounting
model. All joint arrangements are required to be reassessed on
transition to IFRS 11 to determine their type to apply the appropriate
accounting. The adoption of this standard is not expected to have any
impact on Peyto's financial statements.
-- IFRS 12, "Disclosure of Interests in Other Entities" combines in a
single standard the disclosure requirements for subsidiaries, associates
and joint arrangements as well as unconsolidated structured entities.
The adoption of this standard is not expected to have a material impact
on Peyto's financial statements.
-- IFRS 13, "Fair Value Measurement" defines fair value, establishes a
framework for measuring fair value and sets out disclosure requirements
for fair value measurements. This standard defines fair value as the
price that would be received to sell an asset or paid to transfer a
liability in an orderly transaction between market participants at the
measurement date. The adoption of this standard is not expected to have
a material impact on Peyto's financial statements.
As of January 1, 2015, Peyto will be required to adopt IFRS 9 "Financial
Instruments", which is the result of the first phase of the International
Accounting Standards Board ("IASB") project to replace IAS 39 "Financial
Instruments: Recognition and Measurement". The new standard replaces the current
multiple classification and measurement models for financial assets and
liabilities with a single model that has only two classification categories:
amortized cost and fair value. Portions of the standard remain in development
and the full impact of the standard on Peyto's Consolidated Financial Statements
will not be known until the project is complete.
3. Corporate Acquisition
On August 14, 2012, Peyto completed the acquisition, by plan of arrangement, of
all issued and outstanding common shares of Open Range. The total consideration
of approximately $187.2 million was paid for by the issuance of 5.4 million
common shares of Peyto and the assumption of Open Range's long-term debt and
working capital deficiency ($190.4 million was allocated to Property, plant &
equipment). Transaction costs of approximately $0.7 million are included in
general and administrative expenses in the Consolidated Income Statement.
Fair value of net assets acquired
----------------------------------------------------------------------------
Working capital (1,868)
Property, plant and equipment 190,385
Financial derivative instruments (1,132)
Bank debt (72,000)
Decommissioning provision (5,127)
Deferred income taxes 1,929
----------------------------------------------------------------------------
Total net assets acquired 112,187
----------------------------------------------------------------------------
Consideration
Shares issued (5,404,007 shares) 112,187
----------------------------------------------------------------------------
Total purchase price 112,187
----------------------------------------------------------------------------
The above amounts are estimates, which were made by management at the time of
the preparation of these consolidated financial statements based on information
then available. Amendments may be made as amounts subject to estimates are
finalized.
If Peyto had acquired Open Range on January 1, 2012, the pro-forma results of
the oil and gas sales, net income and comprehensive income for the period ended
December 31, 2012 would have been as follows;
Open Range
As Stated January 1, 2012 Pro Forma
December 31, to August 14, December 31,
2012 2012 2012
----------------------------------------------------------------------------
Oil and gas sales 380,647 27,756 408,403
Net income 93,951 1,134 95,085
Comprehensive income 66,966 1,134 68,100
----------------------------------------------------------------------------
4. Property, plant and equipment, net
Cost
----------------------------------------------------------------------------
At December 31, 2010 1,452,242
----------------------------------------------------------------------------
Additions 392,309
Dispositions (785)
----------------------------------------------------------------------------
At December 31, 2011 1,843,766
----------------------------------------------------------------------------
Acquisitions through business combinations 190,385
Additions 466,506
Dispositions (17,649)
----------------------------------------------------------------------------
At December 31, 2012 2,483,008
----------------------------------------------------------------------------
Accumulated depletion and depreciation
----------------------------------------------------------------------------
At December 31, 2010 (84,373)
----------------------------------------------------------------------------
Depletion and depreciation (130,678)
Dispositions 505
----------------------------------------------------------------------------
At December 31, 2011 (214,546)
----------------------------------------------------------------------------
Depletion and depreciation (172,338)
Dispositions 146
----------------------------------------------------------------------------
At December 31, 2012 (386,738)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Carrying amount at December 31, 2012 2,096,270
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Proceeds received for assets disposed of during 2012 were $21.9 million (2011 -
$3.0 million).
In September 2012, Peyto acquired producing properties for net proceeds of $16.7
million, which were allocated to property, plant and equipment of $17.4 million
and decommissioning liabilities of $0.7 million. The properties are in Peyto's
core area of production. The impact on revenue and net income is not
significant.
During 2012 Peyto capitalized $7.8 million (2011 - $5.5 million) of general and
administrative expense directly attributable to exploration and development
activities.
The Company did not have any indicators of impairment in the current or prior
years.
5. Long-term debt
----------------------------------------------------------------------------
December 31, 2012 December 31, 2011
----------------------------------------------------------------------------
Bank credit facility 430,000 470,000
Senior secured notes 150,000 -
----------------------------------------------------------------------------
Balance, end of the year 580,000 470,000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company has a syndicated $730 million extendible revolving credit facility
with a stated term date of April 28, 2013. The bank facility is made up of a $30
million working capital sub-tranche and a $700 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 will
bear interest at rates ranging from prime plus 1.0% to prime plus 2.5%
determined by the Company's 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.
On January 3, 2012, Peyto issued CDN $100 million of senior secured notes
pursuant to a note purchase and private shelf agreement. The notes were issued
by way of private placement and rank equally with Peyto's obligations under its
bank facility. The notes are secured under the General Security Agreement with a
floating charge on land registered in Alberta is held as collateral. The notes
have a coupon rate of 4.39% and mature on January 3, 2019. Interest will be paid
semi-annually in arrears.
On September 6, 2012, Peyto issued CDN $50 million of senior secured notes
pursuant to a note purchase and private shelf agreement. The notes were issued
by way of private placement and rank equally with Peyto's obligations under its
bank facility. The notes are secured under the General Security Agreement with a
floating charge on land registered in Alberta is held as collateral. The notes
have a coupon rate of 4.88% and mature on September 6, 2022. Interest will be
paid semi-annually in arrears.
Upon the issuance of the senior secured notes January 3, 2012, Peyto became
subject to the following financial covenants as defined in the credit facility
and note purchase and private shelf agreements:
-- Senior Debt to EBITDA Ratio will not exceed 3.0 to 1.0
-- Total Debt to EBITDA Ratio will not exceed 4.0 to 1.0
-- Interest Coverage Ratio will not be less than 3.0 to 1.0
-- Total Debt to Capitalization Ratio will not exceed 0.55:1.0
Peyto is in compliance with all financial covenants at December 31, 2012.
Peyto's total borrowing capacity is $880 million and Peyto's net credit facility
is $730 million.
The fair value of all senior notes as at December 31, 2012, is $149.9 million
compared to a carrying value of $150.0 million.
Total interest expense for 2012 was $25.4 million (2011 - $21.9 million) and the
average borrowing rate for 2012 was 4.7% (2011 - 4.8%).
6. Decommissioning provision
The Company makes provision for the future cost of decommissioning wells,
pipelines and facilities on a discounted basis based on the commissioning of
these assets.
The decommissioning provision represents the present value of the
decommissioning costs related to the above infrastructure, which are expected to
be incurred over the economic life of the assets. The provisions have been based
on the Company's internal estimates on the cost of decommissioning, the discount
rate, the inflation rate and the economic life of the infrastructure.
Assumptions, based on the current economic environment, have been made which
management believes are a reasonable basis upon which to estimate the future
liability. These estimates are reviewed regularly to take into account any
material changes to the assumptions. However, actual decommissioning costs will
ultimately depend upon the future market prices for the necessary
decommissioning work required which will reflect market conditions at the
relevant time. Furthermore, the timing of the decommissioning is likely to
depend on when production activities ceases to be economically viable. This in
turn will depend and be directly related to the current and future commodity
prices, which are inherently uncertain.
The following table reconciles the change in decommissioning provision:
----------------------------------------------------------------------------
Balance, December 31, 2010 24,734
----------------------------------------------------------------------------
New or increased provisions 4,764
Accretion of discount 840
Change in discount rate and estimates 7,699
----------------------------------------------------------------------------
Balance, December 31, 2011 38,037
----------------------------------------------------------------------------
New or increased provisions 13,908
Accretion of discount 1,044
Change in discount rate and estimates 5,212
----------------------------------------------------------------------------
Balance, December 31, 2012 58,201
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Current -
Non-current 58,201
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company has estimated the net present value of its total decommissioning
provision to be $58.2 million as at December 31, 2012 ($38.0 million at December
31, 2011) based on a total future undiscounted liability of $127.9 million
($101.2 million at December 31, 2011). At December 31, 2012 management estimates
that these payments are expected to be made over the next 50 years with the
majority of payments being made in years 2041 to 2062. The Bank of Canada's long
term bond rate of 2.36 per cent (2.49 per cent at December 31, 2011) and an
inflation rate of 2.0 per cent (2.0 per cent at December 31, 2011) were used to
calculate the present value of the decommissioning provision.
7. Shareholders' capital
Authorized: Unlimited number of voting common shares
Issued and Outstanding
Number of Common Amount
Common Shares (no par value) Shares $
----------------------------------------------------------------------------
Balance, December 31, 2010 131,875,382 755,831
----------------------------------------------------------------------------
Common shares issued 4,899,000 115,126
Common share issuance costs (net of tax) - (3,854)
Common shares issued by private placement 906,196 17,150
Common shares issued pursuant to DRIP 113,527 1,973
Common shares issued pursuant to OTUPP 166,196 2,889
----------------------------------------------------------------------------
Balance, December 31, 2011 137,960,301 889,115
----------------------------------------------------------------------------
Common shares issued 4,628,750 115,024
Common shares issued for acquisition 5,404,007 112,187
Common share issuance costs (net of tax) - (3,896)
Common shares issued by private placement 525,655 11,952
----------------------------------------------------------------------------
Balance, December 31, 2012 148,518,713 1,124,382
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 could elect to reinvest their monthly
cash distributions in additional trust units at a 5 percent discount to market
price. The DRIP plan incorporated an Optional Trust Unit Purchase Plan ("OTUPP")
which provided unitholders enrolled in the DRIP with the opportunity to purchase
additional trust units from treasury using the same pricing as the DRIP. The
DRIP and the OTUPP plans were cancelled December 31, 2010 with the final shares
issued under the plan January 14, 2011.
On December 31, 2010, Peyto 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 $4.7 million ($18.86 per
share).
On December 16, 2011, Peyto closed an offering of 4,899,000 common shares at a
price of $23.50 per common share, receiving proceeds of $110.1 million (net of
issuance costs).
On December 31, 2011 Peyto completed a private placement of 397,235 common
shares to employees and consultants for net proceeds of $9.7 million ($24.52 per
share). These common shares were issued on January 13, 2012.
On March 23, 2012 Peyto completed a private placement of 128,420 common shares
to employees and consultants for net proceeds of $2.2 million ($17.22 per
share).
On August 14, 2012 Peyto issued 5,404,007 common shares which were valued at
$112.2 million (net of issuance costs) ($20.76 per share) in relation to the
closing of a corporate acquisition (Note 3).
On December 11, 2012, Peyto closed an offering of 4,628,750 common shares at a
price of $24.85 per common share, receiving proceeds of $110.0 million (net of
issuance costs).
Shares to be issued
On December 31, 2012 the Company completed a private placement of 154,550 common
shares to employees and consultants for net proceeds of $3.5 million ($22.38 per
share). These common shares were issued on January 7, 2013.
Per share amounts
Earnings per share or unit have been calculated based upon the weighted average
number of common shares outstanding for the year ended December 31, 2012 of
141,093,829 (2011 - 133,196,103). There are no dilutive instruments outstanding.
Dividends
During the year ended December 31, 2012, Peyto declared and paid dividends of
$0.72 per common share or $0.06 per common share per month, totaling $101.6
million (2011 - $0.72 or $0.06 per share per month, $96.1 million).
On January 15, 2013 Peyto declared dividends of $.06 per common share paid on
February 15, 2013. On February 15, 2013, Peyto declared dividends of $0.06 per
common share to be paid to shareholders of records February 28, 2013. These
dividends will be paid March 15, 2013.
Comprehensive income
Comprehensive income consists of earnings and other comprehensive income
("OCI"). OCI comprises the change in the fair value of the effective portion of
the derivatives used as hedging items in a cash flow hedge. "Accumulated other
comprehensive income" is an equity category comprised of the cumulative amounts
of OCI.
Accumulated hedging gains
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 13.
8. Operating expenses
The Company's operating expenses include all costs with respect to day-to-day
well and facility operations. Processing and gathering recoveries related to
jointly controlled assets and third party natural gas reduce operating expenses.
Years ended December 31
2012 2011
----------------------------------------------------------------------------
Field expenses 46,591 38,240
Processing and gathering recoveries (15,331) (10,861)
----------------------------------------------------------------------------
Total operating expenses 31,260 27,379
----------------------------------------------------------------------------
----------------------------------------------------------------------------
9. General and administrative expenses
General and administrative expenses are reduced by operating and capital
overhead recoveries from operated properties.
Years ended December 31
2012 2011
----------------------------------------------------------------------------
General and administrative expenses 12,822 11,402
Overhead recoveries (8,976) (6,491)
----------------------------------------------------------------------------
Net general and administrative expenses 3,846 4,911
----------------------------------------------------------------------------
----------------------------------------------------------------------------
10. Finance costs
Years ended December 31
2012 2011
----------------------------------------------------------------------------
Interest expense 25,401 21,881
Accretion of discount on provisions 1,044 840
----------------------------------------------------------------------------
26,445 22,721
----------------------------------------------------------------------------
----------------------------------------------------------------------------
11. Future performance based compensation
The Company awards performance based compensation to employees annually. The
performance based compensation is comprised of reserve and market value based
components.
Reserve based component
The reserves value based component is 4% of the incremental increase in value,
if any, as adjusted to reflect changes in debt, equity, dividends, general and
administrative costs and interest, of proved producing reserves calculated using
a constant price at December 31 of the current year and a discount rate of 8%.
Market based component
Under the market based component, rights with a three year vesting period are
allocated to employees and key consultants. The number of rights outstanding at
any time is not to exceed 6% of the total number of common shares outstanding.
At December 31 of each year, all vested rights are automatically cancelled and,
if applicable, paid out in cash. Compensation is calculated as the number of
vested rights multiplied by the total of the market appreciation (over the price
at the date of grant) and associated dividends of a common share for that
period. The 2012 market based component was based on i) 0.5 million vested
rights at an average grant price of $13.50, average cumulative distributions of
$1.44 and a ten day weighted average closing price of $18.83, ii) 0.6 million
vested rights at an average grant price of $19.13, average cumulative
distributions of $0.72 and a ten day weighted average price of $24.75 and iii)
0.07 million vested rights at an average grant price of $20.63, average
cumulative dividends of $0.48 and a ten day weighted average price of $22.58.
The total amount expensed under these plans was as follows:
($000) 2012 2011
----------------------------------------------------------------------------
Market based compensation 7,762 17,486
Reserve based compensation 4,825 5,210
----------------------------------------------------------------------------
Total market and reserves based compensation 12,587 22,696
----------------------------------------------------------------------------
----------------------------------------------------------------------------
For the future market based component, compensation costs as at December 31,
2012 were a recovery of $2.8 million related to 0.6 million non-vested rights
with an average grant price of $19.13, average cumulative dividends of $0.72 and
0.1 million non-vested rights with an average grant price of $20.63 and average
cumulative dividends of $0.48. (2011 - 0.6 million non-vested rights with an
average grant price of $13.50 and 1.3 million non-vested rights with an average
grant price of $19.13 were $1.2 million). The cumulative provision for future
performance based compensation as at December 31, 2012 was $2.7 million (2011 -
$5.6 million).
The fair values were calculated using a Black-Scholes valuation model. The
principal inputs to the option valuation model were:
December 31 December 31
2012 2011
----------------------------------------------------------------------------
Share price $22.58 $24.75
Exercise price $18.41 - $19.91 $12.06 - $18.41
Expected volatility 0% 0%
Option life 1 - 2 years 1 - 2 years
Dividend yield 0% 0%
Risk-free interest rate 1.08% 0.97%
----------------------------------------------------------------------------
Subsequent to December 31, 2012, 3.0 million rights were granted at a price of
$22.58 to be valued at the ten day weighted average market price at December 31,
2013 and vesting one third on each of December 31, 2013, December 31, 2014 and
December 31, 2015.
12. Income taxes
($000) 2012 2011
----------------------------------------------------------------------------
Earnings before income taxes 130,093 168,145
Statutory income tax rate 25.00% 26.50%
----------------------------------------------------------------------------
Expected income taxes 32,523 44,558
Increase (decrease) in income taxes from:
Corporate income tax rate change - (2,429)
True-up tax pools 1,634 (7,706)
Resolution of reassessment and other 1,985 5,539
----------------------------------------------------------------------------
Total income tax expense (recovery) 36,142 39,962
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Deferred income tax expense (recovery) 34,274 35,013
Current tax expense 1,868 4,949
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total income tax expense (recovery) 36,142 39,962
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Differences between tax base and reported amounts
for depreciable assets 207,805 167,282
Derivative financial instruments 1,930 11,208
Share issuance costs (3,095) (3,083)
Future performance based bonuses (684) (1,389)
Provision for decommission provision (14,550) (9,509)
Cumulative eligible capital (6,599) (7,096)
Attributable crown royalty income carryforward - (4,964)
Tax loss carry-forwards recognized (10,566) (259)
----------------------------------------------------------------------------
Deferred income taxes 174,241 152,190
----------------------------------------------------------------------------
----------------------------------------------------------------------------
At December 31, 2012 the Company has tax pools of approximately $1,288.0 million
(2011 - $998.1 million) available for deduction against future income. The
Company has approximately $42.1 million in loss carry-forwards (2011 - $0.4
million) available to reduce future taxable income.
Canada Revenue Agency ("CRA") conducted an audit of 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. The Company filed a notice of objection and the CRA
confirmed the reassessment. Examinations for discovery have been completed. The
Tax Court of Canada had agreed to both parties' request to hold the Company's
appeal in abeyance pending a decision of the Supreme Court of Canada to hear
another taxpayer's appeal. The other appeal raised issues that are similar in
principle to those raised in the Company's appeal. As the other taxpayer's
appeal was unsuccessful with the Federal Court of Appeal, in 2011, the Company
expensed the income tax of $4.9 million and interest charges of $2.2 million
assessed and paid in 2008. Subsequently, the Alberta Government reassessed the
same time period resulting in income taxes payable of $1.8 million and interest
charges of $1.4 million paid in 2013.
13. Financial instruments
Financial instrument classification and measurement
Financial instruments of the Company carried on the consolidated balance sheet
are carried at amortized cost with the exception of cash and financial
derivative instruments, specifically fixed price contracts, which are carried at
fair value. There are no significant differences between the carrying amount of
financial instruments and their estimated fair values as at December 31, 2012.
The fair value of the Company's cash and financial derivative instruments are
quoted in active markets. The Company classifies the fair value of these
transactions according to the following hierarchy.
-- Level 1 - quoted prices in active markets for identical financial
instruments.
-- Level 2 - quoted prices for similar instruments in active markets;
quoted prices for identical or similar instruments in markets that are
not active; and model-derived valuations in which all significant inputs
and significant and significant value drivers are observable in active
markets.
-- Level 3 - valuations derived from valuation techniques in which one or
more significant inputs or significant value drivers are unobservable.
The Company's cash and financial derivative instruments have been assessed on
the fair value hierarchy described above and classified as Level 1.
Fair values of financial assets and liabilities
The Company's financial instruments include cash, accounts receivable, financial
derivative instruments, due from private placement, current liabilities,
provision for future performance based compensation and long term debt. At
December 31, 2012 and 2011, 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.
Following is a summary of all risk management contracts in place as at December
31, 2012:
----------------------------------------------------------------------------
Propane Monthly Price
Period Hedged Type Volume (USD)
----------------------------------------------------------------------------
September 1, 2012 to March 31, 2013 Fixed Price 2,000 bbl $49.56/bbl
September 1, 2012 to March 31, 2013 Fixed Price 2,000 bbl $44.10/ bbl
September 1, 2012 to March 31, 2013 Fixed Price 2,000 bbl $32.34/ bbl
September 1, 2012 to March 31, 2013 Fixed Price 2,000 bbl $33.60/ bbl
September 1, 2012 to March 31, 2013 Fixed Price 2,000 bbl $32.97/ bbl
October 1, 2012 to March 31, 2013 Fixed Price 2,000 bbl $34.01/ bbl
October 1, 2012 to March 31, 2013 Fixed Price 2,000 bbl $34.65/ bbl
October 1, 2012 to March 31, 2013 Fixed Price 2,000 bbl $36.96/ bbl
January 1, 2013 to March 31, 2013 Fixed Price 4,000 bbl $36.12/bbl
April 1, 2013 to June 30, 2013 Fixed Price 4,000 bbl $34.86/bbl
April 1, 2013 to December 31, 2013 Fixed Price 4,000 bbl $30.66/bbl
April 1, 2013 to December 31, 2013 Fixed Price 4,000 bbl $32.34/bbl
April 1, 2013 to December 31, 2013 Fixed Price 4,000 bbl $34.86/bbl
April 1, 2013 to December 31, 2013 Fixed Price 4,000 bbl $35.39/bbl
----------------------------------------------------------------------------
Butane Monthly Price
Period Hedged Type Volume (USD)
----------------------------------------------------------------------------
September 1, 2012 to March 31, 2013 Fixed Price 2,000 bbl $80.64/bbl
September 1, 2012 to March 31, 2013 Fixed Price 2,000 bbl $58.38/bbl
September 1, 2012 to March 31, 2013 Fixed Price 2,000 bbl $60.06/bbl
September 1, 2012 to March 31, 2013 Fixed Price 2,000 bbl $60.06/bbl
October 1, 2012 to March 31, 2013 Fixed Price 2,000 bbl $66.36/bbl
----------------------------------------------------------------------------
Iso-Butane Monthly Price
Period Hedged Type Volume (USD)
----------------------------------------------------------------------------
September 1, 2012 to March 31, 2013 Fixed Price 1,000 bbl $82.32/bbl
September 1, 2012 to March 31, 2013 Fixed Price 1,000 bbl $60.48/bbl
September 1, 2012 to March 31, 2013 Fixed Price 1,000 bbl $62.58/bbl
September 1, 2012 to March 31, 2013 Fixed Price 1,000 bbl $62.58/bbl
October 1, 2012 to March 31, 2013 Fixed Price 1,000 bbl $69.30/bbl
----------------------------------------------------------------------------
Natural Gas Daily Price
Period Hedged Type Volume (CAD)
----------------------------------------------------------------------------
April 1, 2011 to March 31, 2013 Fixed Price 5,000 GJ $4.055/GJ
April 1, 2011 to March 31, 2013 Fixed Price 5,000 GJ $3.80/GJ
June 1, 2011 to March 31, 2013 Fixed Price 5,000 GJ $4.17/GJ
June 1, 2011 to March 31, 2013 Fixed Price 5,000 GJ $4.10/GJ
June 1, 2011 to March 31, 2013 Fixed Price 5,000 GJ $4.10/GJ
November 1, 2011 to March 31, 2013 Fixed Price 5,000 GJ $4.00/GJ
April 1, 2012 to October 31, 2013 Fixed Price 5,000 GJ $4.00/GJ
April 1, 2012 to October 31, 2013 Fixed Price 5,000 GJ $4.00/GJ
April 1, 2012 to October 31, 2013 Fixed Price 5,000 GJ $4.00/GJ
April 1, 2012 to October 31, 2013 Fixed Price 5,000 GJ $4.00/GJ
April 1, 2012 to March 31, 2013 Fixed Price 5,000 GJ $2.20/GJ
April 1, 2012 to March 31, 2013 Fixed Price 5,000 GJ $2.31/GJ
April 1, 2012 to October 31, 2013 Fixed Price 5,000 GJ $2.52/GJ
April 1, 2012 to March 31, 2014 Fixed Price 5,000 GJ $3.00/GJ
May 1, 2012 to October 31, 2013 Fixed Price 5,000 GJ $2.30/GJ
August 1, 2012 to March 31, 2014 Fixed Price 5,000 GJ $3.00/GJ
August 1, 2012 to October 31, 2014 Fixed Price 5,000 GJ $3.10/GJ
November 1, 2012 to October 31, 2013 Fixed Price 5,000 GJ $2.60/GJ
November 1, 2012 to October 31, 2013 Fixed Price 5,000 GJ $3.005/GJ
November 1, 2012 to October 31, 2013 Fixed Price 5,000 GJ $3.00/GJ
November 1, 2012 to March 31, 2014 Fixed Price 5,000 GJ $2.81/GJ
November 1, 2012 to March 31, 2014 Fixed Price 5,000 GJ $3.00/GJ
November 1, 2012 to March 31, 2014 Fixed Price 5,000 GJ $3.05/GJ
November 1, 2012 to March 31, 2014 Fixed Price 5,000 GJ $3.02/GJ
November 1, 2012 to October 31, 2014 Fixed Price 5,000 GJ $3.0575/GJ
January 1, 2013 to October 31, 2013 Fixed Price 5,000 GJ $3.42/GJ
January 1, 2013 to December 31, 2013 Fixed Price 5,000 GJ $3.105/GJ
January 1, 2013 to March 31, 2013 Fixed Price 5,000 GJ $3.32/GJ
January 1, 2013 to March 31, 2014 Fixed Price 5,000 GJ $3.00/GJ
January 1, 2013 to March 31, 2014 Fixed Price 5,000 GJ $3.02/GJ
April 1, 2013 to October 31, 2013 Fixed Price 5,000 GJ $3.205/GJ
April 1, 2013 to March 31, 2014 Fixed Price 5,000 GJ $3.105/GJ
April 1, 2013 to March 31, 2014 Fixed Price 5,000 GJ $3.53/GJ
April 1, 2013 to March 31, 2014 Fixed Price 5,000 GJ $3.45/GJ
April 1, 2013 to March 31, 2014 Fixed Price 5,000 GJ $3.50/GJ
April 1, 2013 to March 31, 2014 Fixed Price 5,000 GJ $3.08/GJ
April 1, 2013 to March 31, 2014 Fixed Price 5,000 GJ $3.17GJ
November 1, 2013 to October 31, 2014 Fixed Price 5,000 GJ $3.50/GJ
----------------------------------------------------------------------------
As at December 31, 2012, Peyto had committed to the future sale of 261,000
barrels of natural gas liquids at an average price of $39.86 USD per barrel and
59,810,000 gigajoules (GJ) of natural gas at an average price of $3.19 per GJ or
$3.74 per mcf. Had these contracts been closed on December 31, 2012, Peyto would
have realized a gain in the amount of $7.7 million. If the AECO gas price on
December 31, 2012 were to increase by $1/GJ, the unrealized gain would decrease
by approximately $59.8 million. An opposite change in commodity prices rates
would result in an opposite impact on other comprehensive income.
Subsequent to December 31, 2012 Peyto entered into the following contracts:
----------------------------------------------------------------------------
Monthly Price
Propane Period Hedged Type Volume (USD)
----------------------------------------------------------------------------
April 1, 2013 to December 31, 2013 Fixed Price 4,000 bbl $34.44/bbl
----------------------------------------------------------------------------
Monthly Price
Natural Gas Period Hedged Type Volume (CAD)
----------------------------------------------------------------------------
April 1, 2013 to March 31, 2014 Fixed Price 5,000 GJ $3.10/GJ
April 1, 2013 to October 31, 2014 Fixed Price 5,000 GJ $3.25/GJ
April 1, 2013 to October 31, 2014 Fixed Price 5,000 GJ $3.30/GJ
April 1, 2013 to October 31, 2014 Fixed Price 5,000 GJ $3.33/GJ
April 1, 2013 to October 31, 2014 Fixed Price 7,500 GJ $3.20/GJ
April 1, 2013 to October 31, 2014 Fixed Price 5,000 GJ $3.22/GJ
April 1, 2013 to October 31, 2014 Fixed Price 5,000 GJ $3.20/GJ
April 1, 2013 to October 31, 2014 Fixed Price 5,000 GJ $3.1925/GJ
April 1, 2013 to October 31, 2014 Fixed Price 5,000 GJ $3.25/GJ
April 1, 2013 to October 31, 2014 Fixed Price 5,000 GJ $3.30/GJ
November 1, 2013 to March 31, 2015 Fixed Price 5,000 GJ $3.6025/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 before income tax for the year ended December 31, 2012 would decrease
by $4.2 million. An opposite change in interest rates will result in an opposite
impact on earnings before income tax.
Credit risk
A substantial portion of the Company's accounts receivable is with petroleum and
natural gas marketing entities. Industry standard dictates that commodity sales
are settled on the 25th day of the month following the month of production. The
Company generally extends unsecured credit to purchasers, and therefore, the
collection of accounts receivable may be affected by changes in economic or
other conditions and may accordingly impact the Company's overall credit risk.
Management believes the risk is mitigated by the size, reputation and
diversified nature of the companies to which they extend credit. The Company has
not previously experienced any material credit losses on the collection of
accounts receivable. Of the Company's revenue for the year ended December 31,
2012, approximately 13% was received from one company (December 31, 2011 - 54%,
four companies (18%, 13%, 12% and 11%)). Of the Company's accounts receivable at
December 31, 2012, approximately 14% was receivable from a single company
(December 31, 2011 - 15%, one company). The maximum exposure to credit risk is
represented by the carrying amount on the balance sheet. There are no material
financial assets that the Company considers past due and no accounts have been
written off.
The Company may be exposed to certain losses in the event of non-performance by
counterparties to commodity price contracts. The Company mitigates this risk by
entering into transactions with counterparties that have investment grade credit
ratings.
Counterparties to financial instruments expose the Company to credit losses in
the event of non-performance. Counterparties for derivative instrument
transactions are limited to high credit-quality financial institutions, which
are all members of our syndicated credit facility.
The Company assesses quarterly if there should be any impairment of financial
assets. At December 31, 2012, there was no impairment of any of the financial
assets of the Company.
Liquidity risk
Liquidity risk includes the risk that, as a result of operational liquidity
requirements:
-- The Company will not have sufficient funds to settle a transaction on
the due date;
-- The Company will be forced to sell financial assets at a value which is
less than what they are worth; or
-- The Company may be unable to settle or recover a financial asset at all.
The Company's operating cash requirements, including amounts projected to
complete our existing capital expenditure program, are continuously monitored
and adjusted as input variables change. These variables include, but are not
limited to, available bank lines, oil and natural gas production from existing
wells, results from new wells drilled, commodity prices, cost overruns on
capital projects and changes to government regulations relating to prices,
taxes, royalties, land tenure, allowable production and availability of markets.
As these variables change, liquidity risks may necessitate the need for the
Company to conduct equity issues or obtain debt financing. The Company also
mitigates liquidity risk by maintaining an insurance program to minimize
exposure to certain losses.
The following are the contractual maturities of financial liabilities as at
December 31, 2012:
less than
1 1-2
Year Years 2-5 Years Thereafter
----------------------------------------------------------------------------
Accounts payable and accrued
liabilities 164,946
Dividends payable 8,911
Provision for future market and
reserves based bonus 2,677 59
Current taxes payable 1,890
Long-term debt(1) 430,000
Senior secured notes 150,000
----------------------------------------------------------------------------
(1) Revolving credit facility renewed annually (see Note 5)
14. Capital disclosures
The Company's objectives when managing capital are: (i) to maintain a flexible
capital structure, which optimizes the cost of capital at acceptable risk; and
(ii) to maintain investor, creditor and market confidence to sustain the future
development of the business.
The Company manages its capital structure and makes adjustments to it in light
of changes in economic conditions and the risk characteristics of its underlying
assets. The Company considers its capital structure to include Shareholders'
equity, debt and working capital. To maintain or adjust the capital structure,
the Company may from time to time, issue common shares, raise debt, adjust its
capital spending or change dividends paid to manage its current and projected
debt levels. The Company monitors capital based on the following 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.
There were no changes in the Company's approach to capital management from the
previous year.
December 31 December 31
2012 2011
----------------------------------------------------------------------------
Shareholders' equity 1,210,067 1,015,708
Long-term debt 580,000 470,000
Working capital (surplus) deficit 74,884 (40,232)
----------------------------------------------------------------------------
1,864,951 1,445,476
----------------------------------------------------------------------------
----------------------------------------------------------------------------
15. Related party transactions
An officer and director of the Company is a partner of a law firm that provides
legal services to the Company. For the year ended December 31, 2012, legal fees
totaled $1.2 million (2011 - $0.8 million). As at December 31, 2012, an amount
due to this firm of $1.2 million was included in accounts payable (2011 - $0.7
million).
The Company has determined that the key management personnel consists of it key
employees, officers and directors. In addition to the salaries and directors
fees paid to these individuals, the Company also provides compensation in the
form of market and reserve based bonus to some of these individuals.
Compensation expense of $1.3 million is included in general and administrative
expenses and $5.0 million in market and reserves based bonus relating to key
management personnel for the year 2012 (2011 - $1.7 million in general and
administrative and $10.1 million in market and reserves based bonus).
16.Commitments
Peyto has contractual obligations and commitments as follows:
2013 2014 2015 2016 2017 Thereafter
----------------------------------------------------------------------------
Note repayment(1) - - - - - 150,000
Interest payments(2) 4,635 6,830 6,830 6,830 6,830 18,785
Transportation
commitments 14,033 13,077 9,749 4,575 1,221 924
Operating leases 1,678 1,694 522 - - -
----------------------------------------------------------------------------
Total 20,346 21,601 17,101 11,405 8,051 169,709
----------------------------------------------------------------------------
(1) Long-term debt repayment on senior secured notes
(2) Fixed interest payments on senior secured notes
Officers
Darren Gee Tim Louie
President and Chief Executive Officer Vice President, Land
Scott Robinson David Thomas
Executive Vice President and Chief Vice President, Exploration
Operating Officer
Kathy Turgeon Jean-Paul Lachance
Vice President, Finance and Chief Vice President, Exploitation
Financial Officer
Stephen Chetner
Corporate Secretary
Directors
Don Gray, Chairman
Rick Braund
Stephen Chetner
Brian Davis
Michael MacBean, Lead Independent Director
Darren Gee
Gregory Fletcher
Scott Robinson
Auditors
Deloitte LLP
Solicitors
Burnet, Duckworth & Palmer LLP
Bankers
Bank of Montreal
Union Bank, Canada Branch
Royal Bank of Canada
Canadian Imperial Bank of Commerce
HSBC Bank Canada
The Toronto-Dominion Bank
Alberta Treasury Branches
Canadian Western Bank
Transfer Agent
Valiant Trust Company
Head Office
1500, 250 - 2nd Street SW
Calgary, AB
T2P 0C1
Phone: 403.261.6081
Fax: 403.451.4100
Web: http://www.peyto.com/
Stock Listing Symbol: PEY.TO
Toronto Stock Exchange
FOR FURTHER INFORMATION PLEASE CONTACT:
Peyto Exploration & Development Corp.
1500, 250 - 2nd Street SW
Calgary, AB T2P 0C1
403.261.6081
403.451.4100 (FAX)
www.peyto.com
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