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March 07, 2012 19:47 ET
CALGARY, ALBERTA--(Marketwire - March 7, 2012) - Peyto Exploration & Development Corp. (TSX:PEY) ("Peyto" or the "Company") is pleased to report operating and financial results for the fourth quarter and 2011 fiscal year. Peyto grew production per share and reserves per share to record levels in 2011 while delivering a 74% operating margin(1), 30% profit margin(2), 11% return on capital and 14% return on equity. Highlights for 2011 include:
-- Production per share up 35%. Annual production increased 49% from 142
MMCFe/d (23,728 boe/d) in 2010 to 213 MMCFe/d (35,465 boe/d) in 2011.
-- Reserves per share up 19%. Proved Producing ("PP"), Total Proved ("TP")
and Proved plus Probable Additional ("P+P") reserves increased 15%, 25%,
and 24% (11%, 20%, and 19% per share) to 0.8, 1.4, and 1.9 TCFe,
-- Funds from Operations per share up 22%. Generated $315 million in Funds
from Operations ("FFO") in 2011, or $2.36/share, up from $1.94/share in
-- NAV per share up 9%. Net Asset Value or the Net Present Value per share,
debt adjusted (discounted at 5%) of the Proved plus Probable Additional
assets grew to $36/share in 2011 from $33/share in 2010.
-- FD&A half the field netback. All in FD&A cost for PP, TP and P+P
reserves was $2.12/MCFe ($12.73/boe), $2.13/MCFe and $1.90/MCFe,
respectively including changes in Future Development Capital ("FDC"),
while the average field netback was $3.98/MCFe ($23.88/boe).
-- Capital investments up 43%. Invested $379 million to build a record 130
MMCFe/d (21,700 boe/d) of new production during the year at a cost of
-- Maintained $2/boe operating costs. Industry leading operating costs were
again $0.35/MCFe in 2011.
-- Net Debt to FFO down 13%. The ratio of net debt to Funds from Operations
dropped from 1.7 in 2010 to 1.5 in 2011. Net debt at year end 2011 was
$465 million.
-- Dividends of $0.72/share. A total of $96 million in dividends were paid
to shareholders. Cumulative dividend and distribution payments to date
total $1.2 Billion ($11.59/share).
2011 in Review
Peyto has now completed its 13th year of operations and first year as a dividend paying, growth corporation. Despite the lowest realized natural gas price in 12 years, the company built a record 21,700 boe/d and executed the largest capital program in its history. As a result, funds from operations grew faster than net debt over the year, strengthening Peyto's balance sheet. The profitability of the $379 million capital program, as measured by the internal rate of return of the new 2011 wells, was estimated to be 31%. This meant the size of the capital program was successfully increased 43% without any loss of efficiency or profitability. Peyto's future opportunities again grew faster than its producing assets with two new undeveloped locations added for each well drilled. Continued facility expansions in 2011, built to accommodate growing production, resulted in total owned and operated facility capacity increasing 40% to over 320 mmcf/d. With an even greater inventory of profitable opportunities, a stronger balance sheet, and insulation from low natural gas prices due to the lowest cash costs in the industry, Peyto remains well positioned to continue delivering superior total returns in 2012.
(1) Operating Margin is defined as Funds from Operations divided by Revenue before Royalties but including realized hedging gains (losses).
(2) Profit Margin is defined as Net Earnings for the year divided by Revenue before Royalties but including realized hedging gains (losses).
Natural gas volumes recorded in thousand cubic feet (mcf) are converted to barrels of oil equivalent (boe) using the ratio of six (6) thousand cubic feet to one (1) barrel of oil (bbl). Natural gas liquids and oil volumes in barrel of oil (bbl) are converted to thousand cubic feet equivalent (mcfe) using a ratio of one (1) barrel of oil to six (6) thousand cubic feet. This could be misleading if used in isolation as it is based on an energy equivalency conversion method primarily applied at the burner tip and does not represent a value equivalency at the wellhead.
3 Months Ended December 31 %
2011 2010 Change
Natural gas (mcf/d) 212,715 148,551 43%
Oil & NGLs (bbl/d) 3,947 3,439 15%
Thousand cubic feet equivalent
(mcfe/d @ 1:6) 236,394 169,184 40%
Barrels of oil equivalent (boe/d
@ 6:1) 39,399 28,197 40%
Product prices
Natural gas ($/mcf) 4.21 4.93 (15)%
Oil & NGLs ($/bbl) 88.04 67.06 31%
Operating expenses ($/mcfe) 0.35 0.31 13%
Transportation ($/mcfe) 0.12 0.14 (14)%
Field netback ($/mcfe) 4.32 4.75 (9)%
General & administrative expenses
($/mcfe) 0.05 (0.05) 200%
Interest expense ($/mcfe) 0.35 0.36 (3)%
Financial ($000, except per share)
Revenue 114,263 88,633 29%
Royalties 9,870 7,712 28%
Funds from operations 80,410 69,201 16%
Funds from operations per share 0.60 0.55 9%
Total dividends 24,245 46,299 (48)%
Total dividends per share 0.18 0.36 (50)%
Payout ratio (%) 30 67 (55)%
Earnings 26,036 95,419 (73)%
Earnings per share 0.19 0.76 (75)%
Capital expenditures 94,688 113,403 (17)%
Weighted average shares
outstanding 133,913,301 125,726,450 7%
As at December 31
Net debt (before future
compensation expense and
unrealized hedging gains)
Shareholders' equity
Total assets
12 Months Ended December 31 %
2011 2010 Change
Natural gas (mcf/d) 189,653 122,031 55%
Oil & NGLs (bbl/d) 3,856 3,389 14%
Thousand cubic feet equivalent
(mcfe/d @ 1:6) 212,789 142,366 49%
Barrels of oil equivalent (boe/d
@ 6:1) 35,465 23,728 49%
Product prices
Natural gas ($/mcf) 4.47 5.36 (17)%
Oil & NGLs ($/bbl) 81.67 65.31 25%
Operating expenses ($/mcfe) 0.35 0.35 -
Transportation ($/mcfe) 0.13 0.13 -
Field netback ($/mcfe) 4.46 5.02 (11)%
General & administrative expenses
($/mcfe) 0.06 0.07 (14)%
Interest expense ($/mcfe) 0.28 0.39 (28)%
Financial ($000, except per share)
Revenue 424,560 319,426 33%
Royalties 41,064 33,406 23%
Funds from operations 314,622 236,956 33%
Funds from operations per share 2.36 1.94 22%
Total dividends 96,068 175,268 (45)%
Total dividends per share 0.72 1.44 (50)%
Payout ratio (%) 31 74 (58)%
Earnings 128,183 200,414 (36)%
Earnings per share 0.96 1.66 (42)%
Capital expenditures 379,061 264,364 43%
Weighted average shares
outstanding 133,196,301 120,548,796 10%
As at December 31
Net debt (before future
compensation expense and
unrealized hedging gains) 465,391 404,944 15%
Shareholders' equity 1,015,708 844,783 20%
Total assets 1,800,252 1,475,253 22%
3 Months
December 12 Months Ended
31 December 31
($000) 2011 2010 2011 2010
Cash flows from operating
activities 85,592 65,545 289,995 222,532
Change in non-cash working
capital (19,139) (20,157) 3,085 (17,737)
Change in provision for
performance based compensation (8,739) (6,051) (1,154) 2,297
Performance based compensation 22,696 29,864 22,696 29,864
Funds from operations 80,410 69,201 314,622 236,956
Funds from operations per share 0.60 0.55 2.36 1.94
(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 distributions may vary.
The Peyto Strategy
When Peyto commenced operations thirteen years ago it had no cash flow to fund its capital expenditures and no land holdings. Initial seed capital was raised and invested into the exploration and development of producing reserves in the Alberta Deep Basin. As a result of continued success, Peyto has built a long life natural gas business with some of the lowest total costs in the energy sector today. The ability to effectively re-invest cash flow and use a small amount of debt in the development of new producing reserves has allowed Peyto to generate high returns for shareholders. This manufacturing approach takes raw material, undeveloped land, and turns it into a finished product, oil and natural gas production. That production is then sold for more than the total costs to manufacture it. On average, Peyto has sold the production for 1.6 times the total cost required to make it (both capital and production cost). Peyto has been able to re-invest those profits to grow and also reward shareholders on their investment with distribution or dividend payments, the combination of which have provided substantial total returns.
As illustrated in the following table, cash flow generated from the business has played a dominant role in the overall funding of Peyto's capital expenditures and has historically contributed to a low cost of capital.
Year Ended December 31
($millions)(1) 2011 2010 2009 2008
Cumulative funds from operations
(net of cash bonuses paid and
private placements to
employees) 2,170 1,869 1,654 1,458
Total equity issued (net of
dividends/distributions paid) (345) (375) (469) (399)
Net debt 465 405 440 493
Cumulative Capital Expenditures 2,290 1,899 1,625 1,552
(1) Results prior to 2010 are reported in accordance with previous Canadian GAAP, otherwise are reported in accordance with IFRS.
While this manufacturing strategy of using funds from operations to "build it for less than we sell it" may seem inherently logical and obvious, it is not commonplace in the energy industry and sets Peyto apart as a unique energy company. The success of the Peyto strategy continues to be affirmed.
Capital Expenditures
Peyto's capital program for 2011 was a record $379.1 million, up 43% from the $264.4 million invested in 2010. The goal coming into 2011 was to scale up the size and pace of the previous year's capital program without a loss in capital efficiency or profitability. That goal was successfully achieved.
Drilling and completions (net of Drilling Royalty Credits) accounted for $279.5 million (74%), while wellsite equipment and pipeline connections accounted for $32.3 million (9%). Facility expansions at all three greater Sundance gas plants accounted for $39.7 million (10%). At the same time, 63 new sections of deep basin lands were purchased in 2011 for an average cost of $519/acre, which along with additional seismic acquisitions totaled $23.9 million (6%). Peyto successfully acquired one of its partner's interests in the Kakwa area and divested some minor non-core assets for total net acquisition costs of $3.7 million (1%).
During the year, Peyto spud 70 gross (62 net to Peyto) wells and brought on production 66 gross (58 net) new gas zones. All but one of the wells was drilled horizontally and completed with a multi-stage fracture stimulation. The cost to drill and complete the average horizontal well in 2011 was $4.54 million versus $4.67 million in 2010, while the average well in 2011 was 71m longer at 3,918m. This $130,000 savings per well was partly due to a 19% reduction in drilling times (spud to rig release) as well as operational efficiencies gained from optimization and improvements in execution. All of the wells drilled in 2011 qualify for the Natural Gas Deep Drilling Program royalty holiday.
The following table summarizes capital expenditures for the year.
Three Months ended Twelve Months ended
Dec. 31 Dec. 31
($000) 2011 2010(i) 2011 2010(i)
Land 5,910 8,049 21,002 12,600
Seismic 1,245 92 2,859 224
Drilling - Exploratory &
Development 77,570 87,056 279,446 202,439
Production Equipment, Facilities
& Pipelines 10,644 14,766 72,079 49,100
Acquisitions 527 5,024 5,581 5,724
Dispositions (1,208) (1,584) (1,906) (5,499)
Total Capital Expenditures 94,688 113,403 379,061 264,364
(i)2010 capital was restated from the reported $261.5 million to comply with IFRS
Peyto was successful growing reserves and values in all categories in 2011. The following table illustrates the change in reserve volumes and Net Present Value ("NPV") of future cash flows, discounted at 5%, before income tax using forecast pricing.
% Change, debt
As at December 31 adjusted per
2011 2010 % Change share(i)
Reserves (BCFe)
Proved Producing 765 664 15% 13%
Total Proved 1,352 1,078 25% 23%
Proved + Probable
Additional 1,935 1,558 24% 22%
Net Present Value
($millions) Discounted at
Proved Producing $2,624 $2,363 11% 6%
Total Proved $3,972 $3,404 17% 12%
Proved + Probable
Additional $5,484 $4,738 16% 11%
(i)Per share or unit reserves are adjusted for changes in net debt by converting debt to equity using the Dec 31 share price of $24.39 for 2011 and unit price of $18.49 for 2010. Net Present Values are adjusted for debt by subtracting net debt from the value prior to calculating per share amounts.
Note: based on the InSite Petroleum Consultants report effective December 31, 2011. The InSite price forecast is available at www.InSitepc.com. For more information on Peyto's reserves, refer to the Press Release dated February 15, 2012 announcing the 2011 Year End Reserve Report which is available on the website at www.peyto.com. The complete statement of reserves data and required reporting in compliance with NI 51-101 will be included in Peyto's Annual Information Form to be released in March 2012.
Performance Ratios
The following table highlights some additional annual performance ratios, to be used for comparative purposes, but it is cautioned that on their own do not measure investment success.
2011 2010 2009 2008 2007
($/mcfe) $ 2.12 $ 2.10 $ 2.26 $ 2.88 $ 2.11
RLI (yrs) 9 11 14 14 13
Ratio 1.9 2.0 1.8 2.3 2.8
Replacement 230% 239% 79% 110% 127%
Total Proved
($/mcfe) $ 2.13 $ 2.35 $ 1.73 $ 3.17 $ 1.57
RLI (yrs) 16 17 21 17 16
Ratio 1.9 1.8 2.3 2.1 3.7
Replacement 452% 456% 422% 139% 175%
Capital ($
millions) $ 1,111 $ 741 $ 446 $ 222 $ 169
Proved plus
($/mcfe) $ 1.90 $ 2.19 $ 1.47 $ 3.88 $ 1.56
RLI (yrs) 22 25 29 23 21
Ratio 2.1 1.9 2.8 1.7 3.7
Replacement 585% 790% 597% 122% 117%
($millions) $ 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
($379+$370)/(1,352-1,078+78) = $2.12/mcfe or $12.73/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 127,458/(39,399x365) = 8.9). 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
(($3.98)/$2.12=1.9). 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 ((1,352-1,078+77.7)/77.7) = 4.52).
Value Creation/Reconciliation
In order to measure the success of the 2011 capital program, it is necessary to quantify the total amount of value created during the year and compare that to the total amount of capital invested. The independent engineers have run last year's evaluation with this year's price forecast to remove the change in value attributable to both commodity prices and changing royalties. This approach isolates the value created by the Peyto team from the value created (or lost) by those changes outside of their control. Since the capital investments in 2011 were funded from a combination of cash flow, debt and equity, it is necessary to know the change in debt and the change in shares outstanding to see if the change in value is truly accretive to shareholders.
At year-end 2011, Peyto's net debt had increased by $60.4 million to $465.4 million and the number of shares outstanding had increased by 5.6 million shares to 138.4 million shares. The change in debt includes all of the capital expenditures, net of Drilling Royalty Credits earned, and the total fixed and performance based compensation paid out during the year.
Based on this reconciliation of changes in BT NPV, the Peyto team was able to create $928 million of Proved Producing, $1.8 billion of Total Proven, and $2.5 billion of Proved plus Probable Additional undiscounted reserve value, with $379.1 million of capital investment. The ratio of capital expenditures to value creation is what Peyto refers to as the NPV recycle ratio, which is simply the undiscounted value addition, resulting from the capital program, divided by the capital investment. For 2011, the Proved Producing NPV recycle ratio is 2.4.
The following table breaks out the value created by Peyto's capital investments and reconciles the changes in debt adjusted NPV of future net revenues using forecast prices and costs as at December 31, 2011.
Proved Producing Total Proved
Discounted at 0% 5% 10% 0% 5% 10%
Before Tax Net
Present Value
at Beginning
of Year
Dec. 31, 2010
using InSite
Jan. 1, 2011
less debt $ 4,098 $ 1,958 $ 1,177 $ 6,388 $ 2,999 $ 1,727
Per Share
at Dec. 31,
2010 $ 30.85 $ 14.75 $ 8.86 $ 48.10 $ 22.58 $ 13.00
2011 sales
costs) $ (346)$ (346)$ (346)$ (346)$ (346)$ (346)
Net Change
due to price
InSite Jan
1, 2011
forecast) $ (336)$ (199)$ (144)$ (595)$ (371)$ (276)
Value Change
due to
revisions) $ 928 $ 745 $ 639 $ 1,789 $ 1,225 $ 925
Before Tax Net
Present Value
at End of
Dec. 31, 2011
using InSite
Jan. 1, 2012
less debt $ 4,344 $ 2,159 $ 1,326 $ 7,236 $ 3,507 $ 2,030
Per Share
at Dec. 31,
($/share) $ 31.40 $ 15.60 $ 9.58 $ 52.30 $ 25.35 $ 14.67
Year over Year
Change in
Before Tax
NPV/share 2% 6% 8% 9% 12% 13%
Year over Year
Change in
Before Tax
($0.72/share) 4% 11% 16% 10% 15% 18%
Proved + Probable Additional
Discounted at 0% 5% 10%
Before Tax Net
Present Value
at Beginning
of Year
Dec. 31, 2010
using InSite
Jan. 1, 2011
less debt $ 9,534 $ 4,333 $ 2,438
Per Share
at Dec. 31,
2010 $ 71.79 $ 32.63 $ 18.36
2011 sales
costs) $ (346)$ (346)$ (346)
Net Change
due to price
InSite Jan
1, 2011
forecast) $ (881)$ (543)$ (400)
Value Change
due to
revisions) $ 2,483 $ 1,575 $ 1,134
Before Tax Net
Present Value
at End of
Dec. 31, 2011
using InSite
Jan. 1, 2012
less debt $ 10,790 $ 5,018 $ 2,825
Per Share
at Dec. 31,
($/share) $ 77.99 $ 36.27 $ 20.42
Year over Year
Change in
Before Tax
NPV/share 9% 11% 11%
Year over Year
Change in
Before Tax
($0.72/share) 10% 13% 15%
Tables may not add due to rounding.
Performance Measures
There are a number of performance measures that are used in the oil and gas industry in an attempt to evaluate how profitably capital has been invested. Peyto believes that the value analysis presented above is the best determination of profitability as it compares the value of what was created relative to what was invested, or what is termed, the NPV recycle ratio. This is because the NPV of an oil and gas asset takes into consideration the reserves, the production forecast, the future royalties and operating costs, future capital and the current commodity price outlook. In 2011, the Proved Producing NPV recycle ratio was 2.4 times. This means for each dollar invested, the Peyto team was able to create 2.4 new dollars of Proved Producing reserve value. The average NPV Recycle Ratio over the last 5 years is 3.6 times for undiscounted future values or 2.6 times for future values discounted at 10%. Alternatively, the discount rate at which the incremental future values equal the capital investment is known as the internal rate of return ("IRR"). For 2011, the IRR for the Proved Producing case is 60%. The historic NPV recycle ratios are presented in the following table.
Dec 31, Dec 31, Dec 31, Dec 31, Dec 31, Dec 31,
Value Creation 2011 2010 2009 2008 2007 2006
NPV0 Recycle Ratio
Proved Producing 2.4 3.5 5.4 2.1 4.7 2.9
Total Proved 4.7 6.1 18.9 2.5 5.5 2.9
Proved + Probable
Additional 6.6 10.3 27.1 2.2 3.8 3.8
-- NPV0 (net present value) recycle ratio is calculated by dividing the
undiscounted NPV of reserves added in the year by the total capital cost
for the period (eg. Proved Producing ($928/$379.1) = 2.4).
Quarterly Review
During the fourth quarter of 2011, Peyto drilled 17 gross (14.6 net) wells and brought 17 gross (13.7 net) zones on production. Total capital expenditures in the fourth quarter were $94.7 million, comprised of $49.0 million for drilling, $28.0 million for completions, and $10.6 million for well tie-ins. No facility capital was required in the quarter and so land and seismic of $7.1 million made up the balance of the capital spent.
Peyto strengthened its northern Cardium land position purchasing 15 sections of new land for $4.7 million and spent an additional $1.2 million on lands related to a new area discovery. A total of 18 sections of new lands were purchased in the quarter at an average purchase price of $486/acre. As well, $1.2 million was spent on 3D seismic to prepare existing lands for development drilling.
Production for the fourth quarter of 2011 was up 40% from Q4 2010 and averaged 236.4 MMcfe/d (39,399 boe/d) including: 212.7 MMcf/d of natural gas, 659 bbl/d of propane, 701 bbl/d of butane, 1,014 bbl/d of pentane, and 1,573 bbl/d of condensate and oil. Realized natural gas prices, before hedging, were down 5% to $3.70/mcf while realized oil and natural gas liquids prices were up 31% to $88.04/bbl. Future sales of natural gas resulted in a realized hedging gain of $0.51/mcf in the quarter, which combined with the natural gas and liquids prices equated to revenue of $5.25/mcfe, down 8% from Q4 2010. Details of the realized prices by component are available in the Management's Discussion and Analysis ("MD&A").
Fourth quarter 2011 cash costs of $1.33/Mcfe included royalties of $0.46/Mcfe, operating costs of $0.35/Mcfe, transportation of $0.12/mcfe, G&A of $0.05/Mcfe and interest of $0.35/Mcfe. These industry leading low costs, when deducted from the revenue of $5.25/Mcfe, led to a cash netback of $3.92/Mcf or a 75% operating margin.
Peyto incurred a one-time charge in the quarter of $7.2 million, resulting from a CRA reassessment of Peyto's 2003 restructuring costs. The actual cash payment for this reassessment was made in 2008 but was under appeal and previously carried as a recovery on the balance sheet.
As a result of a warmer than normal winter and robust natural gas supply, North American gas prices are currently at levels not seen in the company's 13 year history and are insufficient to cover most producer's cash costs. At such unsustainably low levels, the usual response is for producers to shut in their higher cost production and trim back their capital budgets, which then has the effect of reducing supply. When this happens, natural gas prices usually strengthen.
In the meantime, Peyto has forward sold approximately 33% of current 2012 natural gas production. As of March 1, 2012, Peyto had forward sold 37,230,000 gigajoules (GJ) at an average price of $3.86/GJ or $4.51/mcf. Had these contracts been closed at March 1, 2012, the company would have realized a gain in the amount of $53.6 million. Details of these individual contracts are available in the MD&A.
Activity Update
To date in 2012, six rigs have been active throughout Peyto's existing core areas, as well as exploring in a few new areas of the Deep Basin. A total of 13 gross (13 net) wells have rig released to date, all of them horizontal wells, including 6 wells that spud in late 2011. Four of these were drilled in Peyto's northern Cardium areas.
Peyto has brought on production 11 gross (10.3 net) new wells since the beginning of the year. In addition, 3 gross (3 net) wells, with restricted production potential of 12 MMcfe/d (2,000 boe/d), were completed and await tie in. These successful wells are located in new exploration areas with exciting follow up potential. Tie in timing in these new areas is slower than Peyto's main core areas as they are not proximate to company facilities. Peyto is using the current low gas price environment as an opportune time to explore and expand in these new areas.
Peyto does not plan to conduct operations through spring breakup this year as it did in 2011. In the present natural gas price environment, there is no incentive to incur the potential cost premiums that can arise during the unpredictable weather conditions of spring breakup. Consequently, Peyto envisions a period of drilling and completion inactivity from mid-April until the beginning of June. Furthermore, Peyto will remain focused on cost control in this low gas price environment. Any expenditure that relates to operational disruptions, upsets or other forms of downtime will be critically reviewed. If AECO daily natural gas prices drop below $1.00/GJ, Peyto will shut in any production that is processed by third parties and has higher per unit costs. Peyto currently estimates there are 34 operated wells and 40 non-operated wells producing a total of 1.75 MMcfe/d net (290 boe/d) that would be affected in this instance.
The Oldman gas plant enhanced liquids extraction project is progressing on schedule with major equipment fabrication 25% complete. Installation and start up is anticipated for the beginning of the fourth quarter of 2012. In addition to this project, engineering design for similar installations at the Nosehill and Wildhay gas plants is underway with preliminary start-up in early to mid-2013.
2012 Outlook
The timing of Peyto's current 2012 capital program of $400 to $450 million, has been weighted to the later months of the year in order to take advantage of an anticipated reduction in natural gas drilling and therefore reduced service costs. Both natural gas prices and service costs will be monitored carefully and this level of capital investment will only be pursued if Peyto's traditional return objectives can be met. With the current disparity between natural gas and liquids prices, Peyto will focus on its inventory of liquid rich opportunities as well as profitable, low risk facility enhancement projects. The timing of those projects will be accelerated as much as possible.
As one of the lowest cost producers in North America, Peyto is well positioned to endure the current low natural gas price environment. A strong hedge book and flexible balance sheet further this position. With Peyto's proven strategy and an expanded portfolio of profitable opportunities, the Peyto team will endeavor to continue delivering superior total returns for years to come.
Conference Call and Webcast
A conference call will be held with the senior management of Peyto to answer questions with respect to the 2011 fourth quarter and full year financial results on Thursday, March 8th, 2012, at 9:00 a.m. Mountain Standard Time (MST), or 11:00 a.m. Eastern Standard Time (EST). To participate, please call 1-416-340-2219 (Toronto area) or 1-866-266-1798 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 5642520. The replay will be available at 11:00 a.m. MST, 1:00 p.m. EST Thursday, March 8th, 2012 until midnight EDT on Thursday, March 15th, 2012. The conference call can also be accessed through the internet at http://events.digitalmedia.telus.com/peyto/030812/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/Q42011MDandA.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 6, 2012 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 commentary from Peyto's senior management.
Darren Gee, President and CEO
March 7, 2012
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 "2012 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.
Balance Sheet
(Amount in $ thousands)
December 31 December 31 January 1
2011 2010 2010
Current assets
Cash 57,224 7,894 -
Accounts receivable 53,829 55,876 58,305
Due from private placement
(Note 6) 9,740 12,423 2,728
Financial derivative
instruments (Note 12) 38,530 25,247 8,683
Prepaid expenses 3,991 3,280 3,786
163,314 104,720 73,502
Long-term financial derivative
instruments (Note 12) 6,304 2,664 1,254
Prepaid capital 1,414 - 955
Property, plant and equipment,
net (Note 3) 1,629,220 1,367,869 1,178,402
1,636,938 1,370,533 1,180,611
1,800,252 1,475,253 1,254,113
Current liabilities
Accounts payable and accrued
liabilities 110,483 113,592 55,890
Dividends payable (Note 6) 8,278 15,825 13,790
Provision for future
performance based compensation
(Note 10) 4,321 5,340 3,395
123,082 134,757 73,075
Long-term debt (Note 4) 470,000 355,000 435,000
Provision for future
performance based compensation
(Note 10) 1,235 1,369 1,016
Decommissioning provision (Note
5) 38,037 24,734 17,479
Deferred income taxes (Note 11) 152,190 114,610 191,907
661,462 495,713 645,402
Shareholders' or Unitholders'
Shareholders' capital (Note 6) 889,115 755,831 -
Unitholders' capital (Note 6) - - 501,219
Shares or Units to be issued
(Note 6) 9,740 17,285 2,728
Retained earnings 82,889 50,774 25,627
Accumulated other comprehensive
income (Note 6) 33,964 20,893 6,062
1,015,708 844,783 535,636
1,800,252 1,475,253 1,254,113
Approved by the Board of Directors
Michael MacBean, Director
Darren Gee, Director
Income Statement
Years ended December 31
2011 2010
Oil and gas sales 387,240 275,081
Realized gain on hedges (Note 12) 37,320 44,345
Royalties (41,064) (33,405)
Petroleum and natural gas sales,
net 383,496 286,021
Operating (Note 7) 27,379 18,415
Transportation 9,754 6,954
General and administrative (Note
8) 4,911 3,638
Market and reserves based bonus 22,696 29,864
Future performance based
compensation (Note 10) (1,154) 2,298
Interest (Note 9) 21,881 20,057
Accretion of decommissioning
provision (Note 9) 840 683
Depletion and depreciation (Note
3) 130,678 83,770
Gain on disposition of assets
(Note 3) (1,634) (2,249)
215,351 163,430
Earnings before taxes 168,145 122,591
Income tax
Deferred income tax expense
(recovery) (Note 11) 35,013 (77,823)
Income tax expense (Note 11) 4,949 -
Earnings for the year 128,183 200,414
Earnings per share or unit (Note
Basic and diluted $ 0.96 $ 1.66
Weighted average number of common
shares outstanding (Note 6)
Basic and diluted 133,196,103 120,548,796
Statement of Comprehensive Income
Years ended December 31
2011 2010
Earnings for the year 128,183 200,414
Other comprehensive income
Change in unrealized gain (loss) on cash
flow hedges (net of deferred tax; 2011 -
$3.9 million expense (2010 - $3.9 million
expense)) 50,391 59,176
Realized (gain) loss on cash flow hedges (37,320) (44,345)
Comprehensive Income 141,254 215,245
Statement of Changes in Equity
Years ended December 31
2011 2010
Shareholders' / Unitholders' capital,
Beginning of Year 755,831 501,219
Common shares / trust units issued 115,126 218,704
Common shares / trust units issued by
private placement 17,150 2,728
Common shares / trust units issuance costs
(net of tax) (3,854) (7,680)
Common shares / trust units issued pursuant
to DRIP 1,973 10,558
Common shares / trust units issued pursuant
to OTUPP 2,889 30,302
Shareholders' / Unitholders' capital, End of
Year 889,115 755,831
Common shares / trust units to be issued,
Beginning of Year 17,285 2,728
Common shares / trust units issued (17,285) (2,728)
Common shares / trust units to be issued 9,740 17,285
Common shares / trust units to be issued,
End of Year 9,740 17,285
Retained earnings, Beginning of Year 50,774 25,627
Earnings for the year 128,183 200,414
Dividends (Note 6) (96,068) (175,267)
Retained earnings, End of Year 82,889 50,774
Accumulated other comprehensive income,
Beginning of Year 20,893 6,062
Other comprehensive income 13,071 14,831
Accumulated other comprehensive income, End
of Year 33,964 20,893
Total Shareholders' Equity 1,015,708 844,783
Statement of Cash Flows
Years ended December 31
2011 2010
Cash provided by (used in)
operating activities
Earnings 128,183 200,414
Items not requiring cash:
Deferred income tax 35,013 (77,823)
Depletion and depreciation 130,678 83,770
Gain on disposition of assets (1,634) (2,249)
Accretion of decommissioning provision 840 683
Change in non-cash working capital related
to operating activities (Note 15) (3,085) 17,737
289,995 222,532
Financing activities
Issuance of common shares 132,276 262,292
Issuance costs (5,137) (8,272)
Dividends declared (96,068) (162,736)
Increase (decrease) in bank debt 115,000 (80,000)
Change in non-cash working capital related
to financing activities (Note 15) (7,547) (7,660)
138,524 3,624
Investing activities
Additions to property, plant and equipment (379,347) (263,460)
Change in non-cash working capital related
to investing activities (Note 15) 158 45,198
(379,189) (218,262)
Net increase in cash 49,330 7,894
Cash, beginning of year 7,894 -
Cash, end of year 57,224 7,894
The following amounts are included in Cash
flows from operating activities:
Cash interest paid 19,656 20,057
Cash taxes paid - -
Notes to Financial Statements
As at December 31, 2011 and 2010 and January 1, 2010
(Amount in $ thousands, except as otherwise noted)
1. Nature of operations
Peyto Exploration & Development Corp. ("Peyto" or the "Company") is a Calgary based oil and natural gas company. The Company conducts exploration, development and production activities in Canada. Peyto is incorporated and domiciled in the Province of Alberta, Canada. The address of its registered office is 1500, 250 - 2nd Street SW, Calgary, Alberta, Canada, T2P 0C1.
On December 31, 2010, Peyto completed the conversion from an income trust to a corporation pursuant to an arrangement under the Business Corporations Act (Alberta); the ("2010 Arrangement"). As a result of this conversion, trust units of Peyto Energy Trust (the "Trust") were exchanged for common shares of Peyto on a one-for-one basis (see Note 6).
The conversion has been accounted for as a continuity of interests and all comparative information presented for the pre-conversion period is that of the Trust. All transaction costs associated with the conversion were expensed as incurred as general and administration expense.
There were no changes in Peyto's underlying operations associated with the 2010 Arrangement. The financial statements and related financial information have been prepared on a continuity of interest basis, which recognizes Peyto as the successor entity and accordingly all comparative information presented for the preconversion period is that of the Trust. For the convenience of the reader, when discussing prior periods, the financial statements refer to common shares, shareholders and dividends although for the pre-conversion period such items were trust units, unitholders and distributions, respectively.
Following the completion of the 2010 Arrangement, Peyto does not have any subsidiaries.
These financial statements were approved and authorized for issuance by the Board of Directors of Peyto on March 6, 2012.
2. Basis of presentation
These financial statements ("financial statements") for the years ended December 31, 2011 represent the Company's initial presentation of its results and financial position in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board ("IFRS"). Amounts relating to the year ended December 31, 2010 and financial position at January 1, 2010 were previously presented in accordance with Canadian generally accepted accounting principles ("Canadian GAAP"). These amounts have been restated as necessary to be compliant with our accounting policies under IFRS, which are included below.
Reconciliations and descriptions relating to the transition from Canadian GAAP to IFRS are included in Note 17.
a. Summary of significant accounting policies
The precise determination of many assets and liabilities is dependent upon future events and the preparation of periodic financial statements necessarily involves the use of estimates and approximations. Accordingly, actual results could differ from those estimates. The financial statements have, in management's opinion, been properly prepared within reasonable limits of materiality and within the framework of the Company's basis of presentation as disclosed.
The following significant accounting policies have been adopted in the preparation and presentation of the financial report:
b. Significant accounting estimates and judgements
The timely preparation of the 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 market 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 is stated at cost, less accumulated depreciation and accumulated impairment losses.
The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, the initial estimate of the decommissioning provision and borrowing costs for qualifying assets. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset. Costs include expenditures on the construction, installation or completion of infrastructure such well sites, pipelines and facilities including activities such as drilling, completion and tie-in costs, equipment and installation costs, associated geological and human resource costs, including unsuccessful development or delineation wells.
Oil and natural gas asset swaps
For exchanges or parts of exchanges that involve assets, the exchange is accounted for at fair value. Assets are then de-recognized at their current carrying 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
Compensation Other liabilities
Dividends Payable Other liabilities
Long Term Debt Other liabilities
Financial Derivative Instruments Fair value through profit or loss
Derivative instruments and risk management
Derivative instruments are utilized by the Company to manage market risk against volatility in commodity prices. The Company's policy is not to utilize derivative instruments for speculative purposes. The Company has chosen to designate its existing derivative instruments as cash flow hedges. The Company assesses, on an ongoing basis, whether the derivatives that are used as cash flow hedges are highly effective in offsetting changes in cash flows of hedged items. All derivative instruments are recorded on the balance sheet at their fair value. The effective portion of the gains and losses is recorded in other comprehensive income until the hedged transaction is recognized in earnings. When the earnings impact of the underlying hedged transaction is recognized in the 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
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 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
Presentation of financial statements
As of January 1, 2012, the Company will be required to adopt IAS 1, "Presentation of Items of OCI: Amendments to IAS 1 Presentation of Financial Statements." The amendments stipulate the presentation of net earnings and OCI and also require the Company to group items within OCI based on whether the items may be subsequently reclassified to profit or loss. The adoption of the amendments to this standard is not expected to have a material impact on the Company's financial position or results.
Joint arrangements
As of January 1, 2013, the Company will be required to adopt IFRS 11, "Joint Arrangements," which specifies that joint arrangements are classified as either joint operations or joint ventures. Parties to a joint operation retain the rights and obligations to individual assets and liabilities of the operation, while parties to a joint venture have rights to the net assets of the venture. Any arrangement which is not structured through a separate entity or is structured through a separate entity but such separation is ineffective such that the parties to the arrangement have rights to the assets and obligations for the liabilities will be classified as a joint operation. Joint operations shall be accounted for in a manner consistent with jointly controlled assets and operations whereby the Company's contractual share of the arrangement's assets, liabilities, revenues and expenses are included in the consolidated financial statements. Any arrangement structured through a separate vehicle that does effectively result in separation between the Company and the arrangement shall be classified as a joint venture and accounted for using the equity method of accounting. Under the existing IFRS standard, the Company has the option to account for any interests it has in joint ventures using proportionate consolidation or equity accounting. The Company does not expect IFRS 11 to have a material impact on its financial position or results.
Disclosure of interests in other entities
As of January 1, 2013, the Company will be required to adopt IFRS 12, "Disclosure of Interests in Other Entities," which contains new disclosure requirements for interests the Company has in subsidiaries, joint arrangements, associates and unconsolidated structured entities. Required disclosures aim to provide readers of the financial statements with information to evaluate the nature of and risks associated with the Company's interests in other entities and the effects of those interests on the Company's financial statements. The Company intends to adopt IFRS 12 in its financial statements for the annual period beginning on January 1, 2013. The Company does not expect IFRS 12 to have a material impact on its financial position or results.
Investments in associates
As of January 1, 2013, the Company will be required to adopt amendments to IAS 28, "Investments in Associates," which provide additional guidance applicable to accounting for interests in joint ventures or associates when a portion of an interest is classified as held for sale or when the Company ceases to have joint control or significant influence over an associate or joint venture. When joint control or significant influence over an associate or joint venture ceases, the Company will no longer be required to re-measure the investment at that date. When a portion of an interest in a joint venture or associate is classified as held for sale, the portion not classified as held for sale shall be accounted for using the equity method of accounting until the sale is completed at which time the interest is reassessed for prospective accounting treatment. The Company does not expect the amendments to IAS 28 to have a material impact on the financial position or results.
Fair value measurement
As of January 1, 2013, the Company will be required to adopt IFRS 13, "Fair Value Measurement," which replaces fair value measurement guidance contained in individual IFRSs, providing a single source of fair value measurement guidance. The standard provides a framework for measuring fair value and establishes new disclosure requirements to enable readers to assess the methods and inputs used to develop fair value measurements and for recurring valuations that are subject to measurement uncertainty, the effect of those measurements on the financial statements. The Company intends to adopt IFRS 13 prospectively in its financial statements for the annual period beginning on January 1, 2013. The extent of the impact of adoption of IFRS 13 has not yet been determined.
Financial instruments
As of January 1, 2015, the Company will be required to adopt IFRS 9 "Financial Instruments" which covers the classification and measurement of financial assets as part of its project to replace IAS 39 "Financial Instruments: Recognition and Measurement." This standard replaces the current models for financial assets and liabilities with a single model. Under this guidance, entities have the option to recognize financial liabilities at fair value through profit or loss. If this option is elected, entities would be required to reverse the portion of the fair value change due to its own credit risk out of profit or loss and recognize the change in other comprehensive income. The implementation of the issued standard is not expected to have a material impact on the Company's financial position or results.
3. Property, plant and equipment, net
Development and
Production Corporate Total
Assets Assets Assets
At January 1, 2010 1,178,030 1,007 1,179,037
Additions 274,299 - 274,299
Dispositions (1,094) - (1,094)
At December 31, 2010 1,451,235 1,007 1,452,242
Additions 392,309 - 392,309
Dispositions (785) - (785)
At December 31, 2011 1,842,759 1,007 1,843,766
Accumulated depreciation
At January 1, 2010 - (635) (635)
Depletion and depreciation (83,681) (89) (83,770)
Dispositions 32 - 32
At December 31, 2010 (83,649) (724) (84,373)
Depletion and depreciation (130,611) (67) (130,678)
Dispositions 505 - 505
At December 31, 2011 (213,755) (791) (214,546)
Carrying amount at December
31, 2011 1,629,004 216 1,629,220
Proceeds received for assets disposed of during 2011 were $3.0 million (2010 - $4.0 million).
During the year ended December 31 2011, the Company capitalized $5.5 million (2010 - $6.5 million) of general and administrative and share based payments directly attributable to production and development activities.
The Company did not have any indicators of impairment in the current or prior years.
4. Long-term debt
The Company has a syndicated $725 million extendible revolving credit facility with a stated term date of April 29, 2012. The bank facility is made up of a $30 million working capital sub-tranche and a $695 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 1.25% to prime plus 2.75% 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.
Total cash interest expense for the year ended December 31, 2011 was $21.9 million (2010 - $20.1 million) and the average borrowing rate for the year was 4.8% (2010 - 4.6%).
On January 3, 2012, the Company 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 the Company's obligations under its bank facility. The notes have a coupon rate of 4.39% and mature on January 3, 2019. Interest will be paid semi-annually in arrears. Proceeds from the notes were used to repay a portion of the Company's outstanding bank debt. The private shelf agreement provides for the issuance, on an uncommitted basis, of an additional US $25 million of senior notes on or prior to January 3, 2015. A General Security Agreement with a floating charge on land registered in Alberta is held as collateral by the bank.
The Company's total borrowing capacity remains at $725 million; however the net credit facility has been reduced to $625 million in conjunction with the private placement of the CDN $100 million of notes.
5. 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, January 1, 2010 17,479
New or increased provisions 3,163
Accretion of discount 683
Change in discount rate and estimates 3,409
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
Current -
Non-current 38,037
The Company has estimated the net present value of its total decommissioning provision to be $38.0 million as at December 31, 2011 ($24.7 million at December 31, 2010 and $17.5 million at January 1, 2010) based on a total future undiscounted liability of $101.2 million ($86.1 million at December 31, 2010 and $76.3 million at January 1, 2010). At December 31, 2011 management estimates that these payments are expected to be made over the next 50 years with the majority of payments being made in years 2040 to 2061. The Bank of Canada's long term bond rate of 2.49 per cent (3.54 per cent at December 31, 2010 and 4.06 per cent at January 1, 2010) and an inflation rate of two per cent (two per cent at December 31, 2010 and two per cent at January 1, 2010) were used to calculate the present value of the decommissioning provision.
6. Shareholders' capital and Unitholders' capital
Authorized: Unlimited number of voting common shares
Issued and Outstanding
Common Shares and Units (no par Number of Common Amount
value) Shares/Units $
Balance, January 1, 2010 114,920,194 501,219
Trust units issued 13,880,500 218,704
Trust units issuance costs (net of
tax) - (7,680)
Trust units issued by private
placement 196,420 2,728
Trust units issued pursuant to
Trust units issued pursuant to
Exchanged for common shares
pursuant to the 2010 Arrangement
(Note 1) (131,875,382) (755,831)
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
Common shares issued pursuant to
Balance, December 31, 2011 137,960,301 889,115
Units issued
On December 31, 2009, Peyto completed a private placement of 196,420 trust units to employees and consultants for net proceeds of $2.7 million ($13.89 per unit). These trust units were issued on January 6, 2010.
Peyto reinstated its amended distribution reinvestment and optional trust unit purchase plan (the "Amended DRIP Plan") effective with the January 2010 distribution whereby eligible Unitholders could elect to reinvest their monthly cash distributions in additional trust units at a 5% discount to market price. The Distribution Reinvestment Plan ("DRIP") 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.
On April 27, 2010, Peyto closed an offering of 5,566,000 trust units at a price of $13.45 per trust unit, receiving proceeds of $71.7 million (net of issuance costs).
On November 30, 2010, Peyto closed an offering of 8,314,500 trust units at a price of $17.30 per trust unit, receiving proceeds of $138.8 million (net of issuance costs).
Common shares issued
On December 31, 2010, Peyto converted all outstanding trust units into common shares on a one share per trust unit basis. At December 31, 2010 there were 131,875,382 shares outstanding.
On December 31, 2010, the Company completed a private placement of 655,581 common shares to employees and consultants for net proceeds of $12.4 million ($18.95 per share). These common shares were issued on January 6, 2011.
On January 14, 2011, 279,723 common shares (113,527 pursuant to the DRIP and 166,196 pursuant to the OTUPP) were issued for net proceeds of $4.9 million.
On March 25, 2011, Peyto completed a private placement of 250,615 common shares to employees and consultants for net proceeds of $4.7 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).
Shares to be issued
On December 31, 2011 the Company 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.
Per share or per units amounts
Earnings per share or unit have been calculated based upon the weighted average number of common shares outstanding for the year ended December 31, 2011 of 133,196,103 (2010 - 120,548,796). There are no dilutive instruments outstanding.
During the year ended December 31, 2011, Peyto declared and paid dividends of $0.72 per common share or $0.06 per common share per month, totaling $96.1 million (2010 - $1.44 or $0.12 per share per month, $175.3 million).
Comprehensive income
Comprehensive income consists of earnings and other comprehensive income ("OCI"). OCI comprises the change in the fair value of the effective portion of the derivatives used as hedging items in a cash flow hedge. "Accumulated other comprehensive income" is 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 12.
7. Operating expenses
The Company's operating expenses include all costs with respect to day-to-day well and facility operations. Processing and gathering recoveries related to jointly controlled assets and third party natural gas reduces operating expenses.
Years ended December 31
2011 2010
Field expenses 38,240 28,960
Processing and gathering recoveries (10,861) (10,545)
Total operating expenses 27,379 18,415
8. General and administrative expenses
General and administrative expenses are reduced by operating and capital overhead recoveries from operated properties.
Years ended December 31
2011 2010
General and administrative expenses 11,402 11,063
Overhead recoveries (6,491) (7,425)
Net general and administrative expenses 4,911 3,638
9. Finance costs
Years ended December 31
2011 2010
Cash interest expense 21,881 20,057
Accretion of discount on provisions 840 683
22,721 20,740
10. 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. 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 2011 market based component was based on i) 0.5 million vested rights at an average grant price of $9.53, average cumulative distributions of $3.63 and a five day weighted average closing price of $24.52, ii) 0.6 million vested rights at an average grant price of $13.49, average cumulative distributions of $1.44 and a ten day weighted average price of $18.83 and iii) 0.7 million vested rights at an average grant price of $18.83, average cumulative dividends of $0.72 and a ten day weighted average price of $24.75.
The total amount expensed under these plans was as follows:
($000) 2011 2010
Market based compensation 17,486 21,236
Reserve value based compensation 5,210 8,628
Total market and reserves based compensation 22,696 29,864
For the future market based component, compensation costs as at December 31, 2011 were a recovery of $1.2 million related to 0.6 million non-vested rights with an average grant price of $13.50, average cumulative dividends of $1.44 and 1.3 million non-vested rights with an average grant price of $19.13 and average cumulative dividends of $0.72. (2010 - 0.5 million non-vested rights with an average grant price of $9.56 and 1.3 million non-vested rights with an average grant price of $13.49 were $2.3 million). The cumulative provision for future performance based compensation as at December 31, 2011 was $5.6 million (2010 - $6.7 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
2011 2010
Share price $24.75 $18.49
Exercise price $12.06 - $18.41 $6.62 - $11.66
Expected volatility 0% 0% - 28%
Option life 1 - 2 years 1 - 2 years
Dividend yield 0% 0%
Risk-free interest rate 0.97% 1.66%
11. Income taxes
On December 31, 2010, the Company converted from a publicly traded income trust to a publicly traded corporation by way of a plan of arrangement (see Note 1). As a result, for the year ended December 31, 2010, the Company's deferred income tax recovery was calculated on the basis of it being a corporation.
($000) 2011 2010
Earnings before income taxes 168,145 122,591
Statutory income tax rate 26.50% 28.00%
Expected income taxes 44,558 34,325
Increase (decrease) in income taxes from:
Corporate income tax rate change (2,429) (66,933)
True-up tax pools (7,706) (39,260)
Benefits of assets previously not
recognized - (5,967)
Resolution of reassessment and other 5,539 12
Total income tax expense (recovery) 39,962 (77,823)
Deferred income tax expense (recovery) 35,013 (77,823)
Current tax expense 4,949 -
Total income tax expense (recovery) 39,962 (77,823)
Differences between tax base and reported
amounts for depreciable assets 167,282 123,109
Financial derivative asset 11,208 7,356
Share issuance costs (3,083) (2,872)
Future performance based bonuses (1,389) (1,757)
Provision for decommission provision (9,509) (6,184)
Recognition of assets previously under
valuation allowance - (4,967)
Cumulative eligible capital (7,096) -
Attributable crown royalty income
carryforward (4,964) -
Tax loss carry-forwards recognized (259) (75)
Deferred income taxes 152,190 114,610
At December 31, 2011 the Company has tax pools of approximately $998.1 million (December 31, 2010 - $884.0 million) available for deduction against future income. The Company has approximately $0.4 million in loss carry-forwards (2010 - $0.3 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 has 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 raises 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.
12. Financial instruments
Financial instrument classification and measurement
Financial instruments of the Company carried on the balance sheet are carried at amortized cost with the exception of cash and financial derivative instruments, specifically fixed price contracts, which are carried at fair value. There are no significant differences between the carrying amount of financial instruments and their estimated fair values as at December 31, 2011.
The fair value of the Company's cash and financial derivative instruments are quoted in active markets. The Company classifies the fair value of these transactions according to the following hierarchy.
-- Level 1 - quoted prices in active markets for identical financial
-- 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
-- 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, 2011 and 2010, cash and financial derivative instruments are carried at fair value. Accounts receivable, due from private placement, current liabilities and provision for future performance based compensation approximate their fair value due to their short term nature. The carrying value of the long term debt approximates its fair value due to the floating rate of interest charged under the credit facility.
Market risk
Market risk is the risk that changes in market prices will affect the Company's earnings or the value of its financial instruments. Market risk is comprised of commodity price risk and interest rate risk. The objective of market risk management is to manage and control exposures within acceptable limits, while maximizing returns. The Company's objectives, processes and policies for managing market risks have not changed from the previous year.
Commodity price risk management
The Company is a party to certain derivative financial instruments, including fixed price contracts. The Company enters into these contracts with well established counterparties for the purpose of protecting a portion of its future earnings and cash flows from operations from the volatility of petroleum and natural gas prices. The Company believes the derivative financial instruments are effective as hedges, both at inception and over the term of the instrument, as the term and notional amount do not exceed the Company's firm commitment or forecasted transactions and the underlying basis of the instruments correlate highly with the Company's exposure.
A summary of contracts outstanding in respect of the hedging activities at December 31, 2011 is as follows:
Effective Value December December
Description Notional (1) Term Rate Level 31, 2011 31, 2010
Natural gas
financial swaps Level
(1) Notional values as at December 31, 2011 (2) Millions of gigajoules
Daily Price
Natural Gas Period Hedged Type Volume (CAD)
April 1, 2010 to March 31, 2012 Price 5,000 GJ $ 5.67/GJ
April 1, 2010 to March 31, 2012 Price 5,000 GJ $ 5.82/GJ
November 1, 2010 to March 31, 2012 Price 5,000 GJ $ 4.10/GJ
April 1, 2011 to March 31, 2012 Price 5,000 GJ $ 6.20/GJ
April 1, 2011 to March 31, 2012 Price 5,000 GJ $ 5.00/GJ
April 1, 2011 to March 31, 2012 Price 5,000 GJ $ 5.12/GJ
April 1, 2011 to October 31, 2012 Price 5,000 GJ $ 4.05/GJ
April 1, 2011 to October 31, 2012 Price 5,000 GJ $ 4.15/GJ
April 1, 2011 to October 31, 2012 Price 5,000 GJ $ 4.10/GJ
April 1, 2011 to October 31, 2012 Price 5,000 GJ $ 4.00/GJ
April 1, 2011 to March 31, 2013 Price 5,000 GJ $ 4.055/GJ
April 1, 2011 to March 31, 2013 Price 5,000 GJ $ 3.80/GJ
May 1, 2011 to March 31, 2012 Price 5,000 GJ $ 4.00/GJ
June 1, 2011 to March 31, 2013 Price 5,000 GJ $ 4.17/GJ
June 1, 2011 to March 31, 2013 Price 5,000 GJ $ 4.10/GJ
June 1, 2011 to March 31, 2013 Price 5,000 GJ $ 4.10/GJ
November 1, 2011 to March 31, 2012 Price 5,000 GJ $ 4.50/GJ
November 1, 2011 to March 31, 2013 Price 5,000 GJ $ 4.00/GJ
April 1, 2012 to December 31, 2012 Price 5,000 GJ $ 3.3125/GJ
April 1, 2012 to December 31, 2012 Price 5,000 GJ $ 3.395/GJ
April 1, 2012 to October 31, 2013 Price 5,000 GJ $ 4.00/GJ
April 1, 2012 to October 31, 2013 Price 5,000 GJ $ 4.00/GJ
April 1, 2012 to October 31, 2013 Price 5,000 GJ $ 4.00/GJ
April 1, 2012 to October 31, 2013 Price 5,000 GJ $ 4.00/GJ
As at December 31, 2011, the Company had committed to the future sale of 37,750,000 gigajoules (GJ) of natural gas at an average price of $4.08 per GJ or $4.77 per mcf based on the historical heating value of Peyto's natural gas. Had these contracts been closed on December 31, 2011, the Company would have realized a gain in the amount of $44.8 million. If the AECO gas price on December 31, 2011 were to increase by $1/GJ, the unrealized gain would decrease by approximately $37.8 million. An opposite change in commodity prices rates would result in an opposite impact on other comprehensive income.
Subsequent to December 31, 2011 the Company entered into the following contracts:
Daily Price
Natural Gas Period Hedged Type Volume (CAD)
July 1, 2012 to October 31, 2012 Price 5,000 GJ $ 2.32/GJ
July 1, 2012 to October 31, 2012 Price 5,000 GJ $ 2.35/GJ
April 1, 2012 to March 31, 2014 Price 5,000 GJ $ 3.00/GJ
Interest rate risk
The Company is exposed to interest rate risk in relation to interest expense on its revolving credit facility. Currently, the Company has not entered into any agreements to manage this risk. If interest rates applicable to floating rate debt were to have increased by 100 bps (1%) it is estimated that the Company's earnings before income tax for the year ended December 31, 2011 would decrease by $4.5 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, 2011, approximately 54% was received from four companies (18%, 13%, 12% and 11%) (December 31, 2010 - 76%, five companies (20%, 18%, 17%, 11% and 10%)). Of the Company's accounts receivable at December 31, 2011, approximately 15% was receivable from a single company (At December 31, 2010 - 31%, three companies (11%, 10% and 10%). 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, 2011, there was no impairment of any of the financial assets of the Company.
Liquidity risk
Liquidity risk includes the risk that, as a result of operational liquidity requirements:
-- The Company will not have sufficient funds to settle a transaction on
the due date;
-- The Company will be forced to sell financial assets at a value which is
less than what they are worth; or
-- The Company may be unable to settle or recover a financial asset at all.
The Company's operating cash requirements, including amounts projected to complete our existing capital expenditure program, are continuously monitored and adjusted as input variables change. These variables include, but are not limited to, available bank lines, oil and natural gas production from existing wells, results from new wells drilled, commodity prices, cost overruns on capital projects and changes to government regulations relating to prices, taxes, royalties, land tenure, allowable production and availability of markets. As these variables change, liquidity risks may necessitate the need for the Company to conduct equity issues or obtain debt financing. The Company also mitigates liquidity risk by maintaining an insurance program to minimize exposure to certain losses.
The following are the contractual maturities of financial liabilities as at December 31, 2011:
less than
1 1-2
Year Years 2-5 Years Thereafter
Accounts payable and accrued
liabilities 110,483
Dividends payable 8,278
Provision for future market and
reserves based bonus 4,321 1,235
Long-term debt(1) 470,000
1. Revolving credit facility renewed annually (see Note 4)
13. Capital disclosures
The Company's objectives when managing capital are: (i) to maintain a flexible capital structure, which optimizes the cost of capital at acceptable risk; and (ii) to maintain investor, creditor and market confidence to sustain the future development of the business.
The Company manages its capital structure and makes adjustments to it in light of changes in economic conditions and the risk characteristics of its underlying assets. The Company considers its capital structure to include Shareholders' equity, debt and working capital. To maintain or adjust the capital structure, the Company may from time to time, issue common shares, raise debt, adjust its capital spending or change dividends paid to manage its current and projected debt levels. The Company monitors capital based on the following measures: current and projected debt to earnings before interest, taxes, depreciation, depletion and amortization ("EBITDA") ratios, payout ratios and net debt levels. To facilitate the management of these ratios, the Company prepares annual budgets, which are updated depending on varying factors such as general market conditions and successful capital deployment. Currently, all ratios are within acceptable parameters. The annual budget is approved by the Board of Directors. The Company is not subject to any external financial covenants.
There were no changes in the Company's approach to capital management from the previous year.
December 31 December 31
2011 2010
Shareholders' equity 1,015,708 844,783
Long-term debt 470,000 355,000
Working capital (surplus) deficit (40,232) 30,037
1,445,476 1,229,820
14. Related party transactions
An officer and director of the Company is a partner of a law firm that provides legal services to the Company. The fees charged are based on standard rates and time spent on matters pertaining to the Company. For the year ended December 31, 2011, legal fees totaled $0.8 million (2010 - $1.4 million). As at December 31, 2011, an amount due to this firm of $0.7 million was included in accounts payable (2010 - $1.3 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 $1.7 million is included in general and administrative expenses and $10.1 million in market and reserves based bonus relating to key management personnel for the year 2011 (2010 - $1.7 million in general and administrative and $13.0 million in market and reserves based bonus).
15. Supplemental cash flow information
Changes in non-cash working capital balances
Years ended December 31
2011 2010
(Increase)/decrease of assets:
Accounts receivable 2,047 (7,266)
Prepaid expenses (711) 506
Increase/(decrease) of liabilities:
Accounts payable and accrued liabilities (3,109) 57,702
Dividends payable (7,547) 2,035
Provision for future performance based
compensation (1,154) 2,298
(10,474) 55,275
Attributable to operating activities (3,085) 17,737
Attributable to financing activities (7,547) (7,660)
Attributable to investing activities 158 45,198
(10,474) 55,275
16. Commitments and contingencies
Following is a summary of the Company's commitment related to an operating lease as at December 31, 2011.
2012 2013 2014 2015 2016 Thereafter
Operating lease 1,058 1,058 1,058 - - -
Total 1,058 1,058 1,058 - - -
The Company has no other contractual obligations or commitments as at December 31, 2011.
Contingent liability
From time to time, Peyto is the subject of litigation arising out of its day-to-day operations. Damages claimed pursuant to such litigation may be material or may be indeterminate and the outcome of such litigation may materially impact Peyto's financial position or results of operations in the period of settlement. While Peyto assesses the merits of each lawsuit and defends itself accordingly, Peyto may be required to incur significant expenses or devote significant resources to defending itself against such litigation. These claims are not currently expected to have a material impact on Peyto's financial position or results of operations.
Peyto has been named in a Statement of Claim issued by Canadian Natural Resources Limited and affiliates ("CNRL"), claiming $13 million in damages for alleged breaches of duty as operator of jointly owned properties, and an interim and permanent injunction to prevent Peyto from proceeding with the completion of a well on those properties. CNRL alleges that Peyto failed to take proper steps as operator of a joint well (the "Well") on lands that offset 100% Peyto owned lands. Peyto has filed a Statement of Defense defending the allegations set forth in the Statement of Claim. The injunction claimed by CNRL was to prevent Peyto from completing the Well at a target location which had been agreed upon by both parties. Although claimed in the Statement of Claim, CNRL did not apply for an interim injunction, and Peyto completed the Well as planned, but no commercial production was obtained. Affidavits of Records were filed in July, 2006 but CNRL had taken no steps to move the matter forward until February 14, 2007 when it proposed to amend its Statement of Claim to add a subsidiary as an additional Plaintiff and to particularize further its allegations. Accordingly, it remains to be seen whether CNRL will proceed with the action. If the action goes ahead, Peyto intends to defend itself vigorously. Although the outcome of this matter is not determinable at this time, Peyto believes that this claim will not have a material adverse effect on the Company's financial position or results of operations.
17. Transition to IFRS
For all periods up to and including the year ended December 31, 2010, the Company prepared its financial statements in accordance with Canadian GAAP. The Company has prepared financial statements which comply with IFRS's applicable for periods beginning on or after the transition date of January 1, 2010 and the significant accounting policies meeting those requirements are described in Note 2.
The effect of the Company's transition to IFRS is summarized in this note as follows:
i. Transition elections
ii. Reconciliation of the Balance Sheets, Income Statement and Comprehensive
Income as previously reported under Canadian GAAP to IFRS
iii.IFRS adjustments
i. Transition elections
IFRS 1 allows first-time adopters certain exemptions from the general requirement to apply IFRS as effective for December 2011 year ends retrospectively. The Company has taken the following exemptions:
a. IFRS 3 Business Combinations has not been applied to acquisitions of
subsidiaries or of interests in associates and joint ventures that
occurred before January 1, 2010, the Company's date of transition.
b. IFRS 2 Share-based Payment has not been applied to any equity
instruments that were granted on or before November 7, 2002, nor has it
been applied to equity instruments granted after November 7, 2002 that
vested before January 1, 2009.
c. The Company has elected under IFRS 1 First-time Adoption of IFRS to
measure oil and gas assets at the date of transition at a deemed cost
under Canadian GAAP.
d. The Company has elected to apply the exemption from full retrospective
application of decommissioning provisions as allowed under IFRS 1 First
Time Adoption of IFRS. As such the Company has re-measured the
provisions as at January 1, 2010 under IAS 37 Provisions, Contingent
Liabilities and Contingent Assets, and estimated the amount to be
included in the retained earnings on transition to IFRS.
Effect of
IFRS Balance Sheet as at January Notes Canadian Transition
1, 2010 17(iii) GAAP to IFRS IFRS
Current assets
Accounts receivable 58,305 - 58,305
Due from private placement 2,728 - 2,728
Financial derivative instruments 8,683 - 8,683
Prepaid expenses 3,786 - 3,786
73,502 - 73,502
Prepaid capital 955 - 955
Financial derivative instruments 1,254 - 1,254
Property, plant and equipment,
net 1,178,402 - 1,178,402
1,180,611 - 1,180,611
1,254,113 - 1,254,113
Current liabilities
Accounts payable and accrued
liabilities 55,890 - 55,890
Distributions payable 13,790 - 13,790
Provision for future performance
based compensation (d) 2,001 1,394 3,395
71,681 1,394 73,075
Long-term debt 435,000 - 435,000
Provision for future performance
based compensation (d) 1,041 (25) 1,016
Decommissioning provision (c) 10,487 6,992 17,479
Deferred income taxes (e) 123,421 68,486 191,907
569,949 75,453 645,402
Unitholders' equity
Unitholders' capital (e) 500,407 812 501,219
Units to be issued 2,728 - 2,728
Retained earnings 99,749 (74,122) 25,627
Accumulated other comprehensive
income (e) 9,599 (3,537) 6,062
612,483 (76,847) 535,636
1,254,113 - 1,254,113
Effect of
IFRS Balance Sheet as at December Notes Canadian Transition
31, 2010 17(iii) GAAP to IFRS IFRS
Current assets
Cash 7,894 - 7,894
Accounts receivable 55,876 - 55,876
Due from private placement 12,423 - 12,423
Financial derivative instruments 25,247 - 25,247
Inventory and prepaid expenses 3,280 - 3,280
104,720 - 104,720
Financial derivative instruments 2,664 - 2,664
Property, plant and equipment,
net (f) 1,347,191 20,678 1,367,869
1,349,855 20,678 1,370,533
1,454,575 20,678 1,475,253
Current liabilities
Accounts payable and accrued
liabilities 113,592 - 113,592
Dividends payable 15,825 - 15,825
Provision for future performance
based compensation (d) 5,567 (227) 5,340
134,984 (227) 134,757
Long-term debt 355,000 - 355,000
Provision for future performance
based compensation (d) 1,452 (83) 1,369
Decommissioning provision (c) 11,926 12,808 24,734
Deferred income taxes (e) 112,567 2,043 114,610
480,945 14,768 495,713
Shareholders' equity
Shareholders' capital (e) 754,493 1,338 755,831
Shares to be issued 17,285 - 17,285
Retained earnings 46,319 4,455 50,774
Accumulated other comprehensive
income (e) 20,549 344 20,893
838,646 6,137 844,783
1,454,575 20,678 1,475,253
(ii) Reconciliation of earnings
and comprehensive income for Effect of
the year ended December 31, Notes Canadian Transition
2010 17(iii) GAAP to IFRS IFRS
Oil and gas sales 275,081 - 275,081
Realized gain on hedges 44,345 - 44,345
Royalties (33,405) - (33,405)
Petroleum and natural gas
sales, net 286,021 - 286,021
Operating 18,415 - 18,415
Transportation 6,954 - 6,954
General and administrative (f) 6,518 (2,880) 3,638
Performance based compensation (d) 29,864 - 29,864
Future performance based
compensation (d) 3,978 (1,680) 2,298
Interest 20,057 - 20,057
Accretion of decommissioning
provision (c) - 683 683
Depletion and depreciation (f) 94,184 (10,414) 83,770
Gain on disposition of assets (f) - (2,249) (2,249)
179,970 (16,540) 163,430
Earnings before taxes 106,051 16,540 122,591
Deferred income tax recovery (e) 15,787 62,036 77,823
Earnings for the year 121,838 78,576 200,414
Other comprehensive income
Change in unrealized gain
(loss) on cash flow hedges (e) 55,295 3,881 59,176
Realized (gain) loss on cash
flow hedges (44,345) - (44,345)
Comprehensive income for the
year 132,788 82,457 215,245
iii.Notes to the reconciliation of balance sheets, income statement and
comprehensive income from Canadian GAAP to IFRS
a. The Company has elected under IFRS 1 First-time Adoption of IFRS to
measure oil and gas assets at the date of transition to IFRS on a deemed
cost basis. The Canadian GAAP full cost pool was measured upon
transition to IFRS as follows:
i. No exploration or evaluation assets were reclassified from the full
cost pool to exploration and evaluation assets; and
ii. All costs recognized under Canadian GAAP under the full cost pool
were allocated to the producing assets and undeveloped proved
properties on a pro rata basis using reserve volumes.
b. The recognition and measurement of impairment differs under IFRS from
Canadian GAAP. In accordance with IFRS 1 the Company performed an
assessment of impairment for all property, plant and equipment and other
corporate assets at the date of transition. The testing on transition to
IFRS did not result in impairment.
c. Under Canadian GAAP asset retirement obligations were discounted at a
credit adjusted risk free rate. Under IFRS the estimated cash flow to
abandon and remediate the wells and facilities has been risk adjusted
and the provision is discounted at a risk free rate. Upon transition to
IFRS this resulted in a $7.0 million increase in the decommissioning
provision with a corresponding decrease in retained earnings.
As a result of the change in the decommissioning provision, accretion expense for the year ended December 31, 2010 was $0.7 million. In addition, under Canadian GAAP accretion of the discount was included in depletion and depreciation. Under IFRS it is included in accretion of decommissioning provision.
d. Under Canadian GAAP, the Company recognized an expense related to their
share-based payments on an intrinsic value basis. Under IFRS, the
Company is required to recognize the expense using a fair value model
and estimate a forfeiture rate. This increased provision for performance
based compensation and decreased retained earnings at the date of
transition by $1.4 million.
For the year ended December 31, 2010 performance based compensation expense decreased by $1.7 million with a corresponding increase in retained earnings.
e. Under IFRS it is required to account for the rate applicable to a trust
rather than the rate applicable to a corporation. The reversal amounts
related to the rate differential under the trust rate of 39% rather than
the corporate rate of 25% which fully reversed in the comparative
period. The result is that under IFRS the deferred tax liability at
January 1, 2010 was $68.5 million higher than under Canadian GAAP with
the offset a result of rate differential specific to the following three
separate components.
First - The rate change on the tax pools of the Company is a $65.8 million reduction to retained earnings.
Second - The rate change on the Marked-to-Market of financial instruments is a $3.5 million to reduction to accumulated other comprehensive income.
Third - The rate change on the share issuance costs is a credit of $0.8 million to shareholders' capital.
After conversion to a Corporation on December 31, 2010 the rates applicable to the above reverted back to 25% and an income inclusion in the year of $62.0 million substantially reversed the deferred tax liability and related account impacts.
f. Upon transition to IFRS, the Company adopted a policy of depleting oil
and natural gas interests on a unit of production basis over proved plus
probable reserves. The depletion policy under Canadian GAAP was based on
units of production over total proved reserves, less undeveloped land.
In addition depletion was calculated at the Canadian cost centre level
under Canadian GAAP. IFRS requires depletion and depreciation to be
calculated at a unit of account level.
There was no impact of this difference on adoption of IFRS at January 1, 2010 as a result of the IFRS 1 election as discussed in Note 17(i)(c).
For the year ended December 31, 2010 the change in policy to deplete oil and natural gas interest on proved plus probable reserves, the inclusion of undeveloped land and component accounting resulted in a net decrease to depletion and depreciation of $10.4 million with a corresponding change to property, plant and equipment.
As a result of specific general and administrative recoveries guidance under IFRS, the Company has adjusted capitalized costs for the year ended December 31, 2010 by a decrease of $2.9 million to general and administrative expense, respectively with a corresponding increase in retained earnings.
ii. Adjustments to the statement of cash flows
The transition from Canadian GAAP to IFRS had no material impact on cash flows generated by the Company.
Darren Gee Tim Louie
President and Chief Executive Officer Vice President, Land
Scott Robinson
Executive Vice President and Chief David Thomas
Operating Officer Vice President, Exploration
Kathy Turgeon
Vice President, Finance and Chief Jean-Paul Lachance
Financial Officer Vice President, Exploitation
Stephen Chetner
Corporate Secretary
Don Gray, Chairman
Rick Braund
Stephen Chetner
Brian Davis
Michael MacBean, Lead Independent Director
Darren Gee
Gregory Fletcher
Scott Robinson
Deloitte & Touche LLP
Burnet, Duckworth & Palmer LLP
Bank of Montreal
Union Bank, Canada Branch
Royal Bank of Canada
Canadian Imperial Bank of Commerce
HSBC Bank Canada
Alberta Treasury Branches
Canadian Western Bank
Transfer Agent
Valiant Trust Company
Peyto Exploration & Development Corp.1500, 250 - 2nd Street SWCalgary, AB T2P 0C1403.261.6081403.451.4100 (FAX)www.peyto.com
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