Peyto Celebrates 15 Years With Year End 2013 Report to Shareholders
CALGARY, ALBERTA--(Marketwired - Mar 5, 2014) - Peyto
Exploration & Development Corp. (TSX:PEY) ("Peyto" or the
"Company") is pleased to report operating and financial results for
the fourth quarter and the 2013 fiscal year which culminate 15
years of success in the Canadian Energy Industry. Peyto set new
production and reserves per share records in 2013 while delivering
a 76% operating margin1 and a 25% profit margin2. A 10% return on
capital and a 12% return on equity were achieved in 2013 along with
the following Q4 and annual highlights:
- Production per share up 26%. Fourth quarter production was
up 35%, also 35% per share, from 299 MMcfe/d (49,754 boe/d) in Q4
2012 to 404 MMcfe/d (67,296 boe/d) in Q4 2013. Annual
production increased 33%, or 26% per share, from 267 MMcfe/d in
2012 to 356 MMcfe/d in 2013.
- Reserves per share up 19%. Proved Producing ("PP"), Total
Proved ("TP") and Proved plus Probable Additional ("P+P") reserves
increased 12%, 10%, and 19% (the same per share) to 1.1, 1.8, and
2.8 TCFe, respectively.
- Maintained industry leading total cash costs. Royalties,
operating costs, transportation, G&A and interest expense
totaled $1.06/MCFe ($6.36/boe) in both Q4 and on average in 2013,
consistent with $1.05/MCFe on average in 2012.
- Funds from operations per share up 34%. Generated $438
million in Funds from Operations ("FFO") in 2013, or $2.94/share,
up 34% from $2.19/share in 2012. Q4 FFO per share was up 35% from
$0.62 to $0.84.
- Organic capital investment up 28%. Invested a record $578
million to build 38,400 boe/d at a cost of $15,100/boe/d in 2013,
up 28% from the $452 million of organic capital spent in
2012.
- P+P FD&A was half the field netback. All in FD&A
cost for PP, TP and P+P reserves was $2.35/MCFe, $2.23/MCFe and
$1.86/MCFe ($11.16/boe), respectively, including changes in Future
Development Capital ("FDC"), while the average field netback was
$3.65/MCFe ($21.89/boe).
- NAV per share of $38. Net Asset Value ("NAV") or the Net
Present Value per share, debt adjusted (discounted at 5%) of the
P+P reserves was $23/share of developed reserves and $15/share of
undeveloped reserves.
- Earnings per share up 43% and dividends per share up 22%. A
total of $143 million in earnings were generated in 2013
($0.96/share), and $131 million in dividends were paid to
shareholders ($0.88/share). Cumulative dividend/distribution
payments made by Peyto to date total $1.47 Billion
($13.19/share).
2013 in Review
The year 2013 marked Peyto's 15th year in the business of
profitably finding, developing, and producing natural gas in
Alberta's Deep Basin. Peyto invested a record $578 million into
drilling and completing 99 new gas wells, building two new gas
plants at Oldman North and Brazeau River, expanding a third plant
at Swanson, acquiring 49 sections of new multi-zone mineral rights
and purchasing over 170 square miles of 3D seismic. For every well
drilled, two new drilling locations were recognized in Peyto's
reserve report further expanding the Company's NAV. A 42% increase
in annual funds from operations was primarily the result of the 33%
growth in production, as realized commodity prices were only up 5%.
A 52% increase in earnings was commensurate with the increase in
FFO, which allowed for a 33% increase in the monthly dividend
mid-way through the year. The solid returns generated with the
annual capital program drove a 10% return on capital and 12% return
on equity. Including dividends, investors realized a 45% return3
from year end 2012 to year end 2013.
- Operating Margin is defined as Funds from Operations
divided by Revenue before Royalties but including realized hedging
gains (losses).
- Profit Margin is defined as Net Earnings for the year
divided by Revenue before Royalties but including realized hedging
gains (losses).
- Total return is calculated using the December 31, 2012
share price of $22.99 and December 31, 2013 share price of $32.51,
along with $0.88/share of dividend.
Natural gas volumes recorded in thousand cubic feet (mcf)
are converted to barrels of oil equivalent (boe) using the ratio of
six (6) thousand cubic feet to one (1) barrel of oil (bbl). Natural
gas liquids and oil volumes in barrel of oil (bbl) are converted to
thousand cubic feet equivalent (mcfe) using a ratio of one (1)
barrel of oil to six (6) thousand cubic feet. This could be
misleading if used in isolation as it is based on an energy
equivalency conversion method primarily applied at the burner tip
and does not represent a value equivalency at the
wellhead.
|
3 Months Ended December 31 |
% |
|
12 Months Ended December 31 |
% |
|
|
2013 |
2012 |
Change |
|
2013 |
2012 |
Change |
|
Operations |
|
|
|
|
|
|
Production |
|
|
|
|
|
|
|
Natural gas (mcf/d) |
361,870 |
266,808 |
36 |
% |
317,622 |
238,490 |
33 |
% |
|
Oil
& NGLs (bbl/d) |
6,984 |
5,286 |
32 |
% |
6,376 |
4,778 |
33 |
% |
|
Thousand cubic feet equivalent (mcfe/d @ 1:6) |
403,774 |
298,522 |
35 |
% |
355,880 |
267,160 |
33 |
% |
|
Barrels of oil equivalent (boe/d @ 6:1) |
67,296 |
49,754 |
35 |
% |
59,313 |
44,527 |
33 |
% |
Product prices |
|
|
|
|
|
|
|
|
|
Natural gas ($/mcf) |
3.59 |
3.45 |
4 |
% |
3.54 |
3.23 |
10 |
% |
|
Oil
& NGLs ($/bbl) |
69.84 |
73.01 |
(4 |
)% |
70.97 |
73.92 |
(4 |
)% |
|
Operating expenses ($/mcfe) |
0.35 |
0.31 |
13 |
% |
0.35 |
0.32 |
9 |
% |
|
Transportation ($/mcfe) |
0.13 |
0.11 |
18 |
% |
0.12 |
0.12 |
- |
|
|
Field
netback ($/mcfe) |
3.67 |
3.62 |
1 |
% |
3.65 |
3.46 |
5 |
% |
|
General & administrative expenses ($/mcfe) |
0.06 |
0.02 |
200 |
% |
0.04 |
0.04 |
- |
|
|
Interest expense ($/mcfe) |
0.24 |
0.32 |
(25 |
)% |
0.24 |
0.26 |
(8 |
%) |
Financial ($000, except per share) |
|
|
|
|
|
|
|
|
Revenue |
164,455 |
120,310 |
37 |
% |
575,845 |
411,400 |
40 |
% |
Royalties |
10,288 |
9,205 |
12 |
% |
40,450 |
30,754 |
32 |
% |
Funds from operations |
125,164 |
90,078 |
39 |
% |
437,742 |
308,865 |
42 |
% |
Funds from operations per share |
0.84 |
0.62 |
35 |
% |
2.94 |
2.19 |
34 |
% |
Total dividends |
35,702 |
26,178 |
36 |
% |
130,898 |
101,593 |
29 |
% |
Total dividends per share |
0.24 |
0.18 |
33 |
% |
0.88 |
0.72 |
22 |
% |
Payout ratio (%) |
29 |
28 |
4 |
% |
30 |
33 |
(9 |
)% |
Earnings |
37,989 |
25,823 |
47 |
% |
142,627 |
93,951 |
52 |
% |
Earnings per share |
0.26 |
0.18 |
44 |
% |
0.96 |
0.67 |
43 |
% |
Capital expenditures |
154,295 |
156,847 |
(2 |
)% |
578,003 |
617,985 |
(6 |
)% |
Weighted average shares outstanding |
148,758,923 |
145,449,651 |
2 |
% |
148,737,654 |
141,093,829 |
5 |
% |
As at December 31 |
|
|
|
|
|
|
|
|
End of period shares outstanding (includes shares to be
issued) |
|
|
|
|
148,949,448 |
148,673,263 |
- |
|
Net debt (before future compensation expense and
unrealized hedging gains) |
|
|
|
|
946,541 |
662,461 |
43 |
% |
Shareholders' equity |
|
|
|
|
1,200,638 |
1,210,067 |
(1 |
)% |
Total assets |
|
|
|
|
2,555,156 |
2,203,524 |
16 |
% |
|
3 Months Ended December 31 |
|
12 Months Ended December 31 |
|
($000) |
2013 |
|
2012 |
|
2013 |
2012 |
|
Cash
flows from operating activities |
120,473 |
|
78,878 |
|
407,357 |
284,309 |
|
Change in non-cash working capital |
(5,380 |
) |
4,457 |
|
11,667 |
12,920 |
|
Change in provision for performance based compensation |
(6,226 |
) |
(7,712 |
) |
2,421 |
(2,819 |
) |
Income tax paid on account of 2003 reassessment |
- |
|
1,868 |
|
- |
1,868 |
|
Performance based compensation |
16,297 |
|
12,587 |
|
16,297 |
12,587 |
|
Funds from operations |
125,164 |
|
90,078 |
|
437,742 |
308,865 |
|
Funds from operations per share |
0.84 |
|
0.62 |
|
2.94 |
2.19 |
|
(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.
Historical Milestones
Peyto Exploration & Development Corp. was founded in October
1998 with the sole purpose of investing shareholder capital into
oil and gas development for maximum possible return. Now, 15 years
later, that goal remains exactly the same. Only now, there are 15
years of results against which that objective can be measured. In
aggregate, approximately $3.5 billion has been invested, mostly in
the drilling of nearly 1,000 natural gas wells in Alberta's Deep
Basin, and in the construction of over 1,100 km of pipelines and 7
gas processing facilities. These investments have generated $4.4
billion in revenue, paid $675 million in royalties to Albertans,
delivered $3.1 billion in funds from operations and funded $1.5
billion in distributions and dividend payments to shareholders. On
top of that, shareholders today own assets independently valued at
$6.6 billion1, 60% of which are already developed. The value of a
share of Peyto, including dividends and distributions, has
compounded at 53% annually over its history. It is fair to say that
the Peyto strategy has been successful in achieving its
objective.
In simple terms, Peyto is a profitable business - finding,
developing and producing for less than what it receives in sales.
The profitability of the business model is illustrated in the
following table:
($/Mcfe) |
2003 |
|
2004 |
|
2005 |
|
2006 |
|
2007 |
|
2008 |
|
2009 |
|
2010 |
|
2011 |
|
2012 |
|
2013 |
|
Average |
|
Sales Price |
$ |
7.21 |
|
$ |
7.32 |
|
$ |
8.87 |
|
$ |
8.76 |
|
$ |
8.93 |
|
$ |
9.54 |
|
$ |
6.75 |
|
$ |
6.15 |
|
$ |
5.47 |
|
$ |
4.21 |
|
$ |
4.43 |
|
$ |
7.06 |
|
Cost
to develop2 |
$ |
(1.33 |
) |
$ |
(1.60 |
) |
$ |
(2.39 |
) |
$ |
(2.95 |
) |
$ |
(2.11 |
) |
$ |
(2.88 |
) |
$ |
(2.26 |
) |
$ |
(2.10 |
) |
$ |
(2.12 |
) |
$ |
(2.22 |
) |
$ |
(2.35 |
) |
$ |
(2.21 |
) |
Cost to produce3 |
$ |
(2.16 |
) |
$ |
(2.21 |
) |
$ |
(2.76 |
) |
$ |
(2.66 |
) |
$ |
(2.75 |
) |
$ |
(3.01 |
) |
$ |
(1.75 |
) |
$ |
(1.63 |
) |
$ |
(1.35 |
) |
$ |
(1.05 |
) |
$ |
(1.06 |
) |
$ |
(2.04 |
) |
"Profit" |
$ |
3.72 |
|
$ |
3.51 |
|
$ |
3.72 |
|
$ |
3.15 |
|
$ |
4.07 |
|
$ |
3.65 |
|
$ |
2.74 |
|
$ |
2.42 |
|
$ |
2.00 |
|
$ |
0.94 |
|
$ |
1.02 |
|
$ |
2.81 |
|
Payout4 |
$ |
1.36 |
|
$ |
2.28 |
|
$ |
2.81 |
|
$ |
3.47 |
|
$ |
3.92 |
|
$ |
4.25 |
|
$ |
4.03 |
|
$ |
3.37 |
|
$ |
1.24 |
|
$ |
1.04 |
|
$ |
1.01 |
|
$ |
2.62 |
|
- Based on Insite's 2013 reserves report for P+P NPV, 5%
discount
- Cost to develop is the PDP FD&A
- Cost to produce is the total cash costs including
Royalties, Operating costs, Transportation, G&A and
Interest.
- Payout is the annual distribution or dividend in $/mcfe of
production.
The predictability and repeatability of annual performance is a
testament to the success of the Peyto's strategy and the execution
of its business plan. After 15 years, there appears to be no reason
to change.
Capital Expenditures
Peyto executed its largest ever drilling program in 2013,
investing $254 million to drill 99 gross (93.4 net) horizontal gas
wells, $152 million on their multi-stage fracture completions, and
$48.3 million in wellsite equipment and pipelines to connect them
to Company owned gathering systems. Drilling and completion costs
per meter of wellbore have been decreasing, despite a 3% per year
annual inflation in service costs, as execution has continued to
improve. The table below outlines the past four years of horizontal
drilling and completion costs.
|
2010 |
2011 |
2012 |
2013 |
Gross Spuds |
|
52 |
|
70 |
|
86 |
|
99 |
Length (m) |
|
3,762 |
|
3,903 |
|
4,017 |
|
4,179 |
|
|
|
|
|
|
|
|
|
Drilling ($MM) |
$ |
2.763 |
$ |
2.823 |
$ |
2.789 |
$ |
2.720 |
$ per meter |
$ |
734 |
$ |
723 |
$ |
694 |
$ |
651 |
|
|
|
|
|
|
|
|
|
Completion ($MM) |
$ |
1.358 |
$ |
1.676 |
$ |
1.672 |
$ |
1.625 |
$ per meter |
$ |
361 |
$ |
429 |
$ |
416 |
$ |
389 |
The Company invested $112 million in 2013 to build new gas
plants at Oldman North (30 MMcf/d) and Brazeau River (20 MMcf/d),
as well as expand the existing Swanson gas plant (+30 MMcf/d), to
accommodate increased production volumes. A total of $6.4 million
was invested in 49.25 sections of new crown lands ($202/acre) and
$2.5 million on tuck-in acquisitions. In addition, 173 km of 2D and
448 km2 of 3D seismic was acquired for $3 million, for total
capital expenditures of $578 million.
The following table summarizes the capital investments for the
fourth quarter and 2013 year.
|
Three Months ended Dec. 31 |
Twelve Months ended Dec. 31 |
($000) |
2013 |
2012 |
|
2013 |
2012 |
|
Land |
1,144 |
5,206 |
|
6,427 |
10,770 |
|
Seismic |
683 |
612 |
|
2,984 |
1,741 |
|
Drilling |
59,825 |
77,295 |
|
254,000 |
210,946 |
|
Completions |
46,836 |
46,484 |
|
151,752 |
127,042 |
|
Equipping and tie-ins |
12,389 |
22,168 |
|
48,303 |
46,246 |
|
Facilities and pipelines |
33,418 |
25,846 |
|
112,054 |
38,236 |
|
Acquisition of Open Range |
- |
- |
|
- |
187,187 |
|
Acquisitions |
- |
75 |
|
2,483 |
17,841 |
|
Dispositions |
- |
(16,969 |
) |
- |
(17,646 |
) |
(Gains) Losses on Dispositions |
- |
(3,870 |
) |
- |
(4,378 |
) |
Total Capital Expenditures |
154,295 |
156,847 |
|
578,003 |
617,985 |
|
Reserves
Peyto was successful growing reserves and values in all
categories in 2013, despite the year over year reduction in
commodity price forecasts. The following table illustrates the
change in reserve volumes and Net Present Value ("NPV") of future
cash flows, discounted at 5%, before income tax and using forecast
pricing.
|
As at December 31 |
% Change |
|
% Change, debt adjusted per share† |
|
|
2013 |
2012 |
Reserves (BCFe) |
|
|
|
|
Proved Producing |
|
1,061 |
|
945 |
12 |
% |
13 |
% |
Total
Proved |
|
1,827 |
|
1,659 |
10 |
% |
11 |
% |
Proved + Probable Additional |
|
2,807 |
|
2,353 |
19 |
% |
20 |
% |
|
|
|
|
|
|
|
|
|
Net
Present Value ($millions) Discounted at 5% |
|
|
|
|
|
|
|
|
Proved Producing |
$ |
3,156 |
$ |
2,806 |
12 |
% |
3 |
% |
Total
Proved |
$ |
4,544 |
$ |
4,166 |
9 |
% |
2 |
% |
Proved + Probable Additional |
$ |
6,587 |
$ |
5,732 |
15 |
% |
11 |
% |
†Per share reserves are adjusted for changes in net
debt by converting debt to equity using the Dec 31 share price of
$22.99 for 2012 and share price of $32.51 for 2013. Net Present
Values are adjusted for debt by subtracting net debt from the value
prior to calculating per share amounts. |
|
Note: based on the InSite Petroleum Consultants
("InSite") report effective December 31, 2013.The InSite price
forecast is available at www.insitepc.com. For more
information on Peyto's reserves, refer to the Press Releases dated
February 12, 2014 and February 14, 2013 announcing the Year End
Reserve Report which is available on the website at
http://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
2014. |
Value Creation/Reconciliation
In order to measure the success of all of the capital invested
in 2013, it is necessary to quantify the total amount of value
added during the year and compare that to the total amount of
capital invested. The independent engineers have run last year's
reserve evaluation with this year's price forecast to remove the
change in value attributable to both commodity prices and changing
royalties. This approach isolates the value created by the Peyto
team from the value created (or lost) by those changes outside of
their control (ie. commodity prices). Since the capital investments
in 2013 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 2013, Peyto's estimated net debt had increased by
$284.1 million to $946.5 million while the number of shares
outstanding had increased by 0.276 million shares to 148.949
million shares. The change in debt includes all of the capital
expenditures, as well as any acquisitions, and the total fixed and
performance based compensation paid out for the year.
Based on this reconciliation of changes in BT NPV, the Peyto
team was able to create $867 million of Proved Producing, $1.129
billion of Total Proven, and $2.307 billion of Proved plus Probable
Additional undiscounted reserve value, with $578 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 2013, the Proved Producing
NPV recycle ratio is 1.5. This means for each dollar invested, the
Peyto team was able to create 1.5 new dollars of Proved Producing
reserve value. The average Proved Producing NPV Recycle Ratio over
the last 5 years is 2.9 times for undiscounted future values or 2.0
times for future values discounted at 10%.
The historic NPV recycle ratios are presented in the following
table.
Value Creation |
31-Dec-06 |
|
31-Dec-07 |
|
31-Dec-08 |
|
31-Dec-09 |
|
31-Dec-10 |
|
31-Dec-11 |
|
31-Dec-12 |
|
31-Dec-13 |
NPV0 Recycle Ratio |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Producing |
2.9 |
|
4.7 |
|
2.1 |
|
5.4 |
|
3.5 |
|
2.4 |
|
1.6 |
|
1.5 |
|
Total
Proved |
2.9 |
|
5.5 |
|
2.5 |
|
18.9 |
|
6.1 |
|
4.7 |
|
2.2 |
|
2.0 |
|
Proved + Probable Additional |
3.8 |
|
3.8 |
|
2.2 |
|
27.1 |
|
10.3 |
|
6.6 |
|
3.2 |
|
4.0 |
*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 ($867/$578) = 1.5).
Performance Measures
There are a number of performance measures that are used in the
oil and gas industry in an attempt to evaluate how profitably
capital has been invested. Peyto believes that the value analysis
and reconciliation presented above is the best determination of
profitability as it compares the value of what was created relative
to what was invested. This is because the NPV of an oil and gas
asset takes into consideration the reserves, the production
forecast, the future royalties and operating costs, future capital
and the current commodity price outlook.
The following table highlights additional annual performance
ratios both before and after the implementation of horizontal wells
in late 2009. These can be used for comparative purposes, but it is
cautioned that on their own they do not measure investment
success.
|
2013 |
|
2012 |
|
2011 |
|
2010 |
|
2009 |
|
2008 |
|
2007 |
|
Proved Producing |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FD&A ($/mcfe) |
$ |
2.35 |
|
$ |
2.22 |
|
$ |
2.12 |
|
$ |
2.10 |
|
$ |
2.26 |
|
$ |
2.88 |
|
$ |
2.11 |
|
|
RLI
(yrs) |
|
7 |
|
|
9 |
|
|
9 |
|
|
11 |
|
|
14 |
|
|
14 |
|
|
13 |
|
|
Recycle Ratio |
|
1.5 |
|
|
1.3 |
|
|
1.9 |
|
|
2.0 |
|
|
1.8 |
|
|
2.6 |
|
|
2.8 |
|
|
Reserve Replacement |
|
190 |
% |
|
284 |
% |
|
230 |
% |
|
239 |
% |
|
79 |
% |
|
110 |
% |
|
127 |
% |
Total Proved |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FD&A ($/mcfe) |
$ |
2.23 |
|
$ |
2.04 |
|
$ |
2.13 |
|
$ |
2.35 |
|
$ |
1.73 |
|
$ |
3.17 |
|
$ |
1.57 |
|
|
RLI
(yrs) |
|
12 |
|
|
15 |
|
|
16 |
|
|
17 |
|
|
21 |
|
|
17 |
|
|
16 |
|
|
Recycle Ratio |
|
1.6 |
|
|
1.4 |
|
|
1.9 |
|
|
1.8 |
|
|
2.3 |
|
|
2.3 |
|
|
3.7 |
|
|
Reserve Replacement |
|
230 |
% |
|
414 |
% |
|
452 |
% |
|
456 |
% |
|
422 |
% |
|
139 |
% |
|
175 |
% |
|
Future Development Capital ($ millions) |
$ |
1,406 |
|
$ |
1,318 |
|
$ |
1,111 |
|
$ |
741 |
|
$ |
446 |
|
$ |
222 |
|
$ |
169 |
|
Proved plus Probable Additional |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FD&A ($/mcfe) |
$ |
1.86 |
|
$ |
1.68 |
|
$ |
1.90 |
|
$ |
2.19 |
|
$ |
1.47 |
|
$ |
3.88 |
|
$ |
1.56 |
|
|
RLI
(yrs) |
|
19 |
|
|
22 |
|
|
22 |
|
|
25 |
|
|
29 |
|
|
23 |
|
|
21 |
|
|
Recycle Ratio |
|
1.9 |
|
|
1.7 |
|
|
2.1 |
|
|
1.9 |
|
|
2.8 |
|
|
1.7 |
|
|
3.7 |
|
|
Reserve Replacement |
|
450 |
% |
|
527 |
% |
|
585 |
% |
|
790 |
% |
|
597 |
% |
|
122 |
% |
|
117 |
% |
|
Future Development Capital ($millions) |
$ |
2,550 |
|
$ |
2,041 |
|
$ |
1,794 |
|
$ |
1,310 |
|
$ |
672 |
|
$ |
390 |
|
$ |
321 |
|
- FD&A (finding, development and acquisition) costs are used
as a measure of capital efficiency and are calculated by dividing
the capital costs for the period, including the change in
undiscounted future development capital ("FDC"), by the change in
the reserves, incorporating revisions and production, for the same
period (eg. Total Proved ($578.0+$87.9)/(304.494-276.419+21.649) =
$2.23/mcfe or $13.39/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
176,882/(67.296x365) = 7.2). 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 (($21.23)/$14.08=1.5). 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
((176.882-157.491+21.649)/21.649) = 190%).
Quarterly Review
Peyto was very active in the fourth quarter of 2013, drilling
and connecting new natural gas wells and commissioning new
processing facilities, just as natural gas prices improved. A total
of 21 gross (20.1 net) wells were drilled, 31 gross (28.3 net)
wells completed and 32 gross (29.5 net) wells equipped and brought
on production. In total, $154.2 million of capital was invested in
the quarter, or 27% of the annual capital program, with $59.8
million spent on drilling, $46.8 million on completions, $12.4
million on pipelines, $33.4 million on facilities and $1.8 million
on lands and seismic.
Production grew over 25%, from 59,000 boe/d at the start of the
fourth quarter, to 75,000 boe/d by the end of the quarter,
averaging 67,296 boe/d, up 35% over Q4 2012. Alberta daily natural
gas prices climbed 45% from $2.31/GJ in the previous quarter to
$3.35/GJ in Q4 2013, just as production rose. Fourth quarter 2013
prices were 4% higher than the same period in 2012. Peyto's
realized price for natural gas in Q4 2013 was $3.43/mcf, prior to a
$0.16/mcf hedging gain, while it's realized liquids price was
$71.98/bbl, prior to a $2.14/bbl hedging loss, yielding a combined
revenue stream of $4.43/mcfe. This net sales price was 1% higher
than same period a year ago.
Total cash costs for Q4 2013 of $1.06/mcfe included royalties of
$0.28/mcfe, operating costs of $0.35/mcfe, transportation of
$0.13/mcfe, G&A of $0.06/mcfe and interest of $0.24/mcfe.
Quarterly cash costs were down slightly from $1.10/mcfe in Q4 2012
but in line with the previous year's average of $1.05/mcfe.
Peyto generated total funds from operations of $125 million in
the quarter, or $3.37/mcfe, equating to a 76% operating margin.
DD&A charges of $1.77/mcfe, as well as a provision for current
and future performance based compensation and tax, reduced FFO to
earnings of $1.02/mcfe, or a 23% profit margin, which funded the
$0.96/mcfe dividend to shareholders.
Marketing
The current natural gas price outlook is for much improved
prices over the next 12 months as cold winter weather has reduced
storage volumes to below seasonal levels. The AECO Monthly strip
for the next 12 months is currently trading at close to $4.70/GJ,
almost 50% higher than the previous 12 months. Beyond that, prices
are expected to return to previous levels as low cost supplies,
reversal of coal-to-gas switching and more seasonal weather
patterns return storage to normal levels. The AECO Monthly strip
for the second year out is currently priced at approximately
$3.80/GJ.
Peyto uses a hedging strategy that is designed to smooth out the
short term fluctuations in the price of natural gas and NGLs
through future sales in order to provide security of price for
capital planning purposes. This is done by selling approximately
35% of the total natural gas production (inclusive of Crown Royalty
volumes) on the daily and monthly spot markets while the balance
(approximately 65%) is pre-sold or hedged. These hedges are meant
to be methodical and consistent and to avoid speculation. In
general, this approach will show hedging losses when short term
prices climb and hedging gains when short term prices fall. Peyto
generally sells its contracts in either the 7 month summer or the 5
month winter season. In order to minimize counterparty risk, these
marketing contracts are all with financial institutions that are
also members of Peyto's banking syndicate. Peyto has deployed this
strategy for over a decade now, which has resulted in $260 million
in cumulative gains. Over the long run, however, Peyto expects to
break even on forward sales, having achieved price security for
little to no cost.
For 2013, Peyto realized a natural gas price of $3.10/GJ or
$3.54/Mcf, for its natural gas sales. This was a combination of 47%
being sold in the daily or monthly spot market, which averaged
$2.98/GJ, and 53% having been pre-sold at an average hedged price
of $3.20/GJ. The following table summarizes the remaining hedged
volumes for the upcoming years effective March 5, 2014:
|
Future Sales |
Average Price (CAD) |
|
GJ |
Mcf |
$/GJ |
$/Mcf |
2014 |
79,117,500 |
68,839,982 |
$ |
3.52 |
$ |
4.05 |
2015 |
24,140,000 |
21,004,167 |
$ |
3.57 |
$ |
4.11 |
Total |
103,257,500 |
89,844,148 |
$ |
3.54 |
$ |
4.06 |
As illustrated in the following table, Peyto's unhedged annual
realized NGL prices(1) were approximately 3% lower on a year over
year basis, and represented 77% of the $93.13/bbl average Edmonton
par oil price in 2013, down from 86% the previous year. Lower
relative Pentane and Butane prices and increased transportation
charges contributed to the increased offset to light oil
prices.
|
Three Months ended Dec. 31 |
Twelve Months ended Dec. 31 |
|
2013 |
2012 |
2013 |
2012 |
Condensate ($/bbl) |
84.92 |
87.02 |
89.85 |
90.41 |
Propane ($/bbl) |
28.55 |
24.40 |
25.38 |
23.01 |
Butane ($/bbl) |
57.26 |
60.46 |
52.73 |
61.09 |
Pentane ($/bbl) |
90.59 |
89.99 |
97.14 |
94.36 |
Total oil and natural gas liquids ($/bbl) |
71.98 |
73.12 |
71.81 |
73.96 |
Edmonton par crude postings ($/bbl) |
86.19 |
84.43 |
93.13 |
85.91 |
- Liquids prices are Peyto realized prices in Canadian
dollars adjusted for fractionation and transportation.
Peyto's hedging practice with respect to propane is similar to
that for natural gas. Effective March 5, 2014, Peyto had a total of
212,000 bbls of Propane forward sold for the remainder of 2014 at
$USD 40.74/bbl.
Activity Update
Drilling activity for the first quarter of 2014 continues to be
robust. Peyto is currently running a 9 rig drilling program
extending across the Greater Sundance area, through Ansell and down
to Brazeau River. The program is targeting ongoing development of
the Bluesky, Wilrich, Falher, Notikewin, and Cardium formations. In
addition to the drilling, a 27 km pipeline was recently completed
connecting a new growth area to Peyto's existing Wildhay Gas Plant.
The new pipeline corridor will provide the necessary infrastructure
for approximately 7 to 10 wells that will be drilled in that area
over the balance of 2014.
Production is currently between 73,000 and 75,000 boe/d with the
exception of a four day period in mid-January during which a
powerful windstorm unexpectedly knocked out power in the Greater
Sundance area for 40 hours and caused the shut in of approximately
60,000 boe/d (655 boe/d on average for the quarter).
Thus far in the quarter, 19 gross (18.1 net) new wells have been
spud with 13 gross (13 net) wells having been completed and brought
onstream. The Company is planning for a continuation of drilling
and completion activity over the traditional April to mid-June
breakup period this year. The level and progress of this planned
activity will be weather and access dependent.
Facility preparations are well underway for continued expansion
at key gas plants. The new Oldman North Gas Plant was expanded in
late February from 30 to 50 MMcf/d with the addition of a third
compressor. This facility will be further expanded to 80 MMcf/d by
the fall. The installation of a refrigeration module and third
compressor at the Brazeau Plant is in the final stages which will
take that facility to 30 MMcf/d of capacity. One additional
compressor is expected after breakup for total Brazeau capacity of
40 MMcf/d. Beyond that, additional compressors and refrigeration
modules are in the fabrication stage for a late summer to early
fall installation at the Oldman North, Wildhay and Swanson
facilities which will bring total capacity additions for the year
to above 100 MMcf/d.
2014 Outlook
The year 2014 looks to be another record breaking year for Peyto
with continued profitable growth. As always, the primary focus is
on maximizing returns, with profitable growth being the by-product
of that success. Peyto's counter-cyclical investment strategy over
the past four years, that has resulted in more than a tripling of
production, should pay off in 2014 as natural gas prices are
forecast to be 50% higher than 2013. These higher prices, however,
will require even greater vigilance with respect to cost control as
it is in these environments when inflation of service costs can
begin to erode future returns. This focus on costs has been at the
heart of Peyto's strategy over the past 15 years and will continue
to be a foundation of the Company's success in the future.
With a firm belief in the future of natural gas and strengthened
with a decade and a half of experience, Peyto remains well
positioned to lead the industry as one of the lowest cost, most
efficient and most profitable energy companies.
Conference Call and Webcast
A conference call will be held with the senior management of
Peyto to answer questions with respect to the 2013 fourth quarter
and full year financial results on Thursday, March 6th, 2014, at
9:00 a.m. Mountain Standard Time (MST), or 11:00 a.m. Eastern
Standard Time (EST). To participate, please call 1-416-340-9432
(Toronto area) or 1-800-769-8320 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 4296819. The replay will be available at
11:00 a.m. MST, 1:00 p.m. EST Thursday, March 6th, 2014 until
midnight EDT on Thursday, March 13th, 2014. The conference call can
also be accessed through the internet at
http://www.gowebcasting.com/5190. 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, audited financial statements and related notes, is
available at http://www.peyto.com/news/Q42013MDandA.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 Tuesday, May 27, 2014 at Livingston Place Conference
Centre, +15 level, 222-3rd Avenue SW, Calgary, Alberta.
Shareholders are encouraged to visit the Peyto website at
www.peyto.com where there is a wealth of information designed to
inform and educate investors. A monthly President's Report can also
be found on the website which follows the progress of the capital
program and the ensuing production growth, along with video and
audio commentary from Peyto's senior management.
Darren Gee, President and CEO
March 5, 2014
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 "2014 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 |
(Amounts in $ thousands) |
|
December 31 2013 |
|
December 31 2012 |
Assets |
|
|
|
Current assets |
|
|
|
Cash |
- |
|
- |
Accounts receivable |
83,714 |
|
85,677 |
Due
from private placement (Note 7) |
6,245 |
|
3,459 |
Derivative financial instruments (Note 13) |
- |
|
10,254 |
Prepaid expenses |
5,666 |
|
4,150 |
|
95,625 |
|
103,540 |
|
|
|
|
Property, plant and equipment, net (Note 4) |
2,459,531 |
|
2,099,984 |
|
2,459,531 |
|
2,099,984 |
|
2,555,156 |
|
2,203,524 |
|
|
|
|
Liabilities |
|
|
|
Current liabilities |
|
|
|
Accounts payable and accrued liabilities |
155,265 |
|
164,968 |
Current income tax |
- |
|
1,868 |
Dividends payable (Note 7) |
11,901 |
|
8,911 |
Derivative financial instruments (Note 13) |
26,606 |
|
- |
Provision for future performance based compensation (Note
11) |
5,100 |
|
2,677 |
|
198,872 |
|
178,424 |
|
|
|
|
Long-term debt (Note 5) |
875,000 |
|
580,000 |
Long-term derivative financial instruments (Note 13) |
5,180 |
|
2,532 |
Provision for future performance based compensation (Note
11) |
3,200 |
|
59 |
Decommissioning provision (Note 6) |
61,184 |
|
58,201 |
Deferred income taxes (Note 12) |
211,082 |
|
174,241 |
|
1,155,646 |
|
815,033 |
|
|
|
|
Equity |
|
|
|
Shareholders' capital (Note 7) |
1,130,069 |
|
1,124,382 |
Shares to be issued (Note 7) |
6,245 |
|
3,459 |
Retained earnings |
86,975 |
|
75,247 |
Accumulated other comprehensive income (Note 7) |
(22,651 |
) |
6,979 |
|
1,200,638 |
|
1,210,067 |
|
2,555,156 |
|
2,203,524 |
Approved by the Board of Directors
Michael MacBean |
Darren Gee |
Director |
Director |
|
|
|
|
Peyto Exploration & Development Corp. |
|
Income Statement |
|
(Amounts in $ thousands) |
|
|
Year ended December 31 |
|
|
2013 |
|
2012 |
|
Revenue |
|
|
|
|
Oil
and gas sales |
|
561,645 |
|
|
357,734 |
|
Realized gain on hedges (Note 13) |
|
14,200 |
|
|
53,667 |
|
Royalties |
|
(40,450 |
) |
|
(30,754 |
) |
Petroleum and natural gas sales, net |
|
535,395 |
|
|
380,647 |
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
Operating (Note 8) |
|
45,235 |
|
|
31,260 |
|
Transportation |
|
16,221 |
|
|
11,275 |
|
General and administrative (Note 9) |
|
5,204 |
|
|
3,846 |
|
Market and reserves based bonus (Note 11) |
|
16,297 |
|
|
12,587 |
|
Future performance based compensation (Note 11) |
|
5,564 |
|
|
(2,819 |
) |
Interest (Note 10) |
|
30,991 |
|
|
25,401 |
|
Accretion of decommissioning provision (Note 10) |
|
1,544 |
|
|
1,044 |
|
Depletion and depreciation (Note 4) |
|
224,976 |
|
|
172,338 |
|
Gain on disposition of assets (Note 4) |
|
- |
|
|
(4,378 |
) |
|
|
346,032 |
|
|
250,554 |
|
Earnings before taxes |
|
189,363 |
|
|
130,093 |
|
|
|
|
|
|
|
|
Income tax |
|
|
|
|
|
|
Deferred income tax expense (Note 12) |
|
46,736 |
|
|
34,274 |
|
Current Income tax expense (Note 12) |
|
- |
|
|
1,868 |
|
Earnings for the year |
|
142,627 |
|
|
93,951 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share (Note 7) |
|
|
|
|
|
|
Basic and diluted |
$ |
0.96 |
|
$ |
0.67 |
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding (Note
7) |
|
|
|
|
|
|
Basic and diluted |
|
148,737,654 |
|
|
141,093,829 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Peyto Exploration & Development Corp. |
|
Statement of Comprehensive Income |
|
(Amounts in $ thousands) |
|
|
Year ended December 31 |
|
|
2013 |
|
2012 |
|
Earnings for the year |
142,627 |
|
93,951 |
|
Other
comprehensive income |
|
|
|
|
Change in unrealized gain (loss) on cash flow hedges |
(25,307 |
) |
17,687 |
|
Deferred tax recovery |
9,877 |
|
8,995 |
|
Realized (gain) loss on cash flow hedges |
(14,200 |
) |
(53,667 |
) |
Comprehensive Income |
112,997 |
|
66,966 |
|
|
|
|
|
Peyto Exploration & Development Corp. |
|
Statement of Changes in Equity |
|
(Amounts in $ thousands) |
|
|
Year ended December 31 |
|
|
2013 |
|
2012 |
|
Shareholders' capital, Beginning of Year |
1,124,382 |
|
889,115 |
|
Common shares issued |
- |
|
115,024 |
|
Common shares issued pursuant to acquisition of Open Range Energy
Corp. |
- |
|
112,187 |
|
Common shares issued by private placement |
5,742 |
|
11,952 |
|
Common shares issuance costs (net of tax) |
(55 |
) |
(3,896 |
) |
Shareholders' capital, End of Year |
1,130,069 |
|
1,124,382 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common shares to be issued, Beginning of Year |
3,459 |
|
9,740 |
|
Common shares issued |
(3,459 |
) |
(9,740 |
) |
Common shares to be issued |
6,245 |
|
3,459 |
|
Common shares to be issued, End of Year |
6,245 |
|
3,459 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retained earnings, Beginning of Year |
75,247 |
|
82,889 |
|
Earnings for the year |
142,627 |
|
93,951 |
|
Dividends (Note 7) |
(130,899 |
) |
(101,593 |
) |
Retained earnings, End of Year |
86,975 |
|
75,247 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive income, Beginning of Year |
6,979 |
|
33,964 |
|
Other comprehensive income (loss) |
(29,630 |
) |
(26,985 |
) |
Accumulated other comprehensive income, End of Year |
(22,651 |
) |
6,979 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Equity |
1,200,638 |
|
1,210,067 |
|
|
|
|
|
|
|
|
|
|
|
Peyto Exploration & Development Corp. |
|
Statement of Cash Flows |
|
(Amounts in $ thousands) |
|
|
Year ended December 31 |
|
|
2013 |
|
2012 |
|
Cash provided by (used in) |
|
|
|
|
Operating activities |
|
|
|
|
Earnings |
142,627 |
|
93,951 |
|
Items not requiring cash: |
|
|
|
|
|
Deferred income tax |
46,736 |
|
34,274 |
|
|
Gain
on disposition of assets |
- |
|
(4,378 |
) |
|
Depletion and depreciation |
224,976 |
|
172,338 |
|
|
Accretion of decommissioning provision |
1,544 |
|
1,044 |
|
|
Long
term portion of future performance based compensation |
3,141 |
|
- |
|
Change in non-cash working capital related to operating
activities |
(11,667 |
) |
(12,920 |
) |
|
407,357 |
|
284,309 |
|
Financing activities |
|
|
|
|
Issuance of common shares |
5,742 |
|
126,976 |
|
Issuance costs |
(73 |
) |
(5,195 |
) |
Cash dividends paid |
(127,908 |
) |
(100,960 |
) |
Increase (decrease) in bank debt |
175,000 |
|
(40,000 |
) |
Issuance of long term notes |
120,000 |
|
150,000 |
|
Repayment of Open Range bank debt |
- |
|
(72,000 |
) |
|
172,761 |
|
58,821 |
|
Investing activities |
|
|
|
|
Additions to property, plant and equipment |
(578,003 |
) |
(429,737 |
) |
Change in prepaid capital |
(5,081 |
) |
(2,300 |
) |
Change in non-cash working capital relating to
investing activities |
2,966 |
|
31,683 |
|
|
(580,118 |
) |
(400,354 |
) |
|
(580,118 |
) |
(400,354 |
) |
|
|
|
|
|
Net increase in cash |
- |
|
(57,224 |
) |
Cash, beginning of year |
- |
|
57,224 |
|
Cash, end of year |
- |
|
- |
|
The following amounts are included in Cash flows from
operating activities: |
|
|
|
|
|
|
|
|
|
Cash interest paid |
23,920 |
|
23,460 |
|
Cash taxes paid |
1,800 |
|
- |
|
|
|
|
|
|
Peyto Exploration & Development
Corp. |
Notes to Financial Statements |
As at December 31, 2013 and 2012 |
(Amounts in $thousands, except as otherwise
noted) |
1. Nature of operations
Peyto Exploration & Development Corp. ("Peyto" or the
"Company") is a Calgary based oil and natural gas company. Peyto
conducts exploration, development and production activities in
Canada. Peyto is incorporated and domiciled in the Province of
Alberta, Canada. The address of its registered office is 1500, 250
- 2nd Street SW, Calgary, Alberta, Canada, T2P 0C1.
Effective December 31, 2012, Peyto completed an amalgamation
with its wholly-owned subsidiary Open Range Energy Corp. ("Open
Range") pursuant to section 184(1) of the Business Corporations
Act (Alberta). Following the amalgamation, Peyto does not have
any subsidiaries.
These financial statements were approved and authorized for
issuance by the Board of Directors of Peyto on March 4, 2014.
2. Basis of presentation
These financial statements ("financial statements") as at and
for the years ended December 31, 2013 and December 31, 2012
represent the Company's results and financial position in
accordance with International Financial Reporting Standards
("IFRS").
a. Summary of significant accounting policies
The precise determination of many assets and liabilities is
dependent upon future events and the preparation of periodic
financial statements necessarily involves the use of estimates and
approximations. Accordingly, actual results could differ from those
estimates. The financial statements have, in management's opinion,
been properly prepared within reasonable limits of materiality and
within the framework of the Company's basis of presentation as
disclosed.
b. Significant accounting estimates and judgements
The timely preparation of the financial statements in conformity
with IFRS requires that management make estimates and assumptions
and use judgment regarding the reported amounts of assets and
liabilities and disclosures of contingent assets and liabilities at
the date of the financial statements and the reported amounts of
revenues and expenses during the period. Such estimates primarily
relate to unsettled transactions and events as of the date of the
financial statements. Accordingly, actual results may differ from
estimated amounts as future confirming events occur.
Amounts recorded for depreciation, depletion and amortization,
decommissioning costs, reserve based bonus 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 determination of CGUs requires judgment in defining a group
of assets that generate cash inflows that are largely independent
of the cash inflows from other assets or groups of assets. CGUs are
determined by, shared infrastructure, commodity type, similar
exposure to market risks and materiality.
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 amount to be paid
out.
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. Recent Accounting Pronouncement
Certain new standards, interpretations, amendments and
improvements to existing standards were issued by the International
Accounting Standards Board (IASB) or International Financial
Reporting Interpretations Committee (IFRIC) that are mandatory for
fiscal year beginning January 1, 2013 or later periods. The
affected standards are consistent with those disclosed in Peyto's
financial statements as at and for the years ended December 31,
2012 and 2011.
Peyto adopted the following standards on January 1, 2013:
IFRS 10 - Consolidated Financial Statements; supersedes IAS 27
"Consolidation and Separate Financial Statements" and SIC-12
"Consolidation - Special Purpose Entities". This standard provides
a single model to be applied in control analysis for all investees
including special purpose entities. This standard became applicable
on January 1, 2013. Peyto adopted the standard on January 1, 2013,
with no impact on Peyto's financial position or results of
operations.
IFRS 11 - Joint Arrangements; requires a venturer to classify
its interest in a joint arrangement as a joint venture or joint
operation. Joint ventures will be accounted for using the equity
method of accounting, whereas joint operations will require the
venturer to recognize its share of the assets, liabilities, revenue
and expenses. This standard became applicable on January 1, 2013.
Peyto adopted the standard on January 1, 2013, with no impact on
Peyto's financial position or results of operations.
IFRS 12 - Disclosure of Interests in Other Entities; establishes
disclosure requirements for interests in other entities, such as
joint arrangements, associates, special purpose vehicles and
off-balance-sheet vehicles. The standard carries forward existing
disclosure and also introduces significant additional disclosure
requirements that address the nature of, and risks associated with,
an entity's interests in other entities. This standard became
effective for Peyto on January 1, 2013. Peyto adopted the standard
on January 1, 2013, with no impact on Peyto's financial position or
results of operations.
IFRS 13 - Fair Value Measurement; defines fair value, sets out a
single IFRS framework for measuring fair value and requires
disclosure about fair value measurements. IFRS 13 applies to
accounting standards that require or permit fair value measurements
or disclosure about fair value measurements (and measurements, such
as fair value less costs to sell, based on fair value or disclosure
about those measurements), except in specified circumstances. IFRS
13 became applicable on January 1, 2013. Peyto adopted the standard
on January 1, 2013, with no impact on Peyto's financial position or
results of operations.
d. Standards issued but not yet effective
As of January 1, 2018, Peyto will be required to adopt IFRS 9
"Financial Instruments", which is the result of the first phase of
the IASB project to replace IAS 39 "Financial Instruments:
Recognition and Measurement". The new standard replaces the current
multiple classification and measurement models for financial assets
and liabilities with a single model that has only two
classification categories: amortized cost and fair value. Portions
of the standard remain in development and the full impact of the
standard on Peyto's Financial Statements will not be known until
the project is complete.
In May 2013, the IASB issued amendments to IAS 36 "Impairment of
Assets" which reduce the circumstances in which the recoverable
amount of CGUs is required to be disclosed and clarify the
disclosures required when an impairment loss has been recognized or
reversed in the period. The amendments are required to be adopted
retrospectively for fiscal years beginning January 1, 2014, with
earlier adoption permitted. These amendments will be applied by
Peyto on January 1, 2014 and the adoption will only impact
disclosures in the notes to the financial statements in periods
when an impairment loss or impairment reversal is recognized.
In May 2013, the IASB issued IFRIC 21 "Levies," which was
developed by the IFRS Interpretations Committee ("IFRIC"). IFRIC 21
clarifies that an entity recognizes a liability for a levy when the
activity that triggers payment, as identified by the relevant
legislation, occurs. The interpretation also clarifies that no
liability should be recognized before the specified minimum
threshold to trigger that levy is reached. IFRIC 21 is required to
be adopted retrospectively for fiscal years beginning January 1,
2014, with earlier adoption permitted. IFRIC 21 will be applied by
Peyto on January 1, 2014 and the adoption may have an impact on
Peyto's accounting for production and similar taxes, which do not
meet the definition of an income tax in IAS 12 "Income Taxes".
Peyto is currently assessing and quantifying the effect on its
financial statements.
e. Presentation currency
All amounts in these financial statements are expressed in
Canadian dollars, as this is the functional and presentation
currency of the Company.
f. Cash Equivalents
Cash equivalents include term deposits or a similar type of
instrument, with a maturity of three months or less when
purchased.
g. 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.
h. 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.
i. Property, plant and equipment
Oil and gas properties and other property, plant and equipment
are stated at cost, less accumulated depreciation and accumulated
impairment losses.
The initial cost of an asset comprises its purchase price or
construction cost, any costs directly attributable to bringing the
asset into operation, the initial estimate of the decommissioning
provision and borrowing costs for qualifying assets. The purchase
price or construction cost is the aggregate amount paid and the
fair value of any other consideration given to acquire the asset.
Costs include expenditures on the construction, installation or
completion of infrastructure such as well sites, pipelines and
facilities including activities such as drilling, completion and
tie-in costs, equipment and installation costs, associated
geological and human resource costs, including unsuccessful
development or delineation wells.
Oil and natural gas asset swaps
For exchanges or parts of exchanges that involve assets, the
exchange is accounted for at fair value. Assets are then
de-recognized at their current carrying amount.
Depletion and depreciation
Oil and natural gas properties are depleted on a
unit-of-production basis over the proved plus probable reserves.
All costs related to oil and natural gas properties (net of salvage
value) and estimated costs of future development of proved plus
probable undeveloped reserves are depleted and depreciated using
the unit-of-production method based on estimated gross proved plus
probable reserves as determined by independent reservoir engineers.
For purposes of the depletion and depreciation calculation,
relative volumes of petroleum and natural gas production and
reserves are converted at the energy equivalent conversion rate of
six thousand cubic feet of natural gas to one barrel of crude
oil.
Other property, plant and equipment are depreciated using a
declining balance method over useful life of 20 years.
j. 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.
k. 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.
l. 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.
m. 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 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 |
Derivative Financial Instruments |
Fair value through profit or loss |
Derivative instruments and risk management
Derivative instruments are utilized by the Company to manage
market risk against volatility in commodity prices. The Company's
policy is not to utilize derivative instruments for speculative
purposes. The Company has chosen to designate its existing
derivative instruments as cash flow hedges. The Company assesses,
on an ongoing basis, whether the derivatives that are used as cash
flow hedges are highly effective in offsetting changes in cash
flows of hedged items. All derivative instruments are recorded on
the balance sheet at their fair value. The effective portion of the
gains and losses is recorded in other comprehensive income until
the hedged transaction is recognized in earnings. When the earnings
impact of the underlying hedged transaction is recognized in the
income statement, the fair value of the associated cash flow hedge
is reclassified from other comprehensive income into earnings. Any
hedge ineffectiveness is immediately recognized in earnings. The
fair values of forward contracts are based on forward market
prices.
Embedded derivatives
An embedded derivative is a component of a contract that causes
some of the cash flows of the combined instrument to vary in a way
similar to a stand-alone derivative. This causes some or all of the
cash flows that otherwise would be required by the contract to be
modified according to a specified variable, such as interest rate,
financial instrument price, commodity price, foreign exchange rate,
a credit rating or credit index, or other variables to be treated
as a financial derivative. The Company has no contracts containing
embedded derivatives.
Normal purchase or sale exemption
Contracts that were entered into and continue to be held for the
purpose of the receipt or delivery of a non-financial item in
accordance with the Company's expected purchase, sale or usage
requirements fall within the exemption from IAS 32 Financial
Instruments: Presentation ("IAS 32") and IAS 39, which is
known as the 'normal purchase or sale exemption'. The Company
recognizes such contracts in its balance sheet only when one of the
parties meets its obligation under the contract to deliver either
cash or a non-financial asset.
n. 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 propane
and 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 derivative financial 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.
o. 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.
p. Provisions
General
Provisions are recognized when the Company has a present
obligation (legal or constructive) as a result of a past event, it
is probable that an outflow of resources embodying economic
benefits will be required to settle the obligation and a reliable
estimate can be made of the amount of the obligation. Where the
Company expects some or all of a provision to be reimbursed, the
reimbursement is recognized as a separate asset but only when the
reimbursement is virtually certain. The expense relating to any
provision is presented in the income statement net of any
reimbursement. If the effect of the time value of money is
material, provisions are discounted using a current pre-tax rate
that reflects, where appropriate, the risks specific to the
liability
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.
q. 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 equity.
r. 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.
s. 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.
t. Share-based payments
Cash-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 cash-settled
share-based payments is expensed on a graded basis over the vesting
period, based on the Company's estimate of liability instruments
that will eventually vest. At the end of each reporting period, the
Company revises its estimate of the number of liability instruments
expected to vest. The impact of the revision of the original
estimates, if any, is recognized in the income statement such that
the cumulative expense reflects the revised estimate, with a
corresponding adjustment to the related liability on the balance
sheet.
u. 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.
v. Share capital
Common shares are classified within equity. Incremental costs
directly attributable to the issuance of shares are recognized as a
deduction from Share capital.
3. Corporate Acquisition
On August 14, 2012, Peyto completed the acquisition, by plan of
arrangement, of all issued and outstanding common shares of Open
Range. The total consideration of approximately $187.2 million was
paid for by the issuance of 5.4 million common shares of Peyto and
the assumption of Open Range's long-term debt and working capital
deficiency ($190.4 million was allocated to Property, plant &
equipment). Transaction costs of approximately $0.7 million were
included in general and administrative expenses in the Income
Statement.
Fair value of net assets acquired |
|
Working capital |
(1,868 |
) |
Property, plant and equipment |
190,385 |
|
Financial derivative instruments |
(1,132 |
) |
Bank
debt |
(72,000 |
) |
Decommissioning provision |
(5,127 |
) |
Deferred income taxes |
1,929 |
|
Total net assets acquired |
112,187 |
|
Consideration |
|
|
Shares issued (5,404,007 shares) |
112,187 |
|
Total purchase price |
112,187 |
|
If Peyto had acquired Open Range on January 1, 2012, the
pro-forma results of the oil and gas sales, net income and
comprehensive income for the period ended December 31, 2012 would
have been as follows;
|
As Stated December 31, 2012 |
Open Range January 1, 2012 to August 14, 2012 |
Pro Forma December 31, 2012 |
Oil
and gas sales |
380,647 |
27,756 |
408,403 |
Net
income |
93,951 |
1,134 |
95,085 |
Comprehensive income |
66,966 |
1,134 |
68,100 |
4. Property, plant and equipment, net
|
|
Cost |
|
At December 31, 2011 |
1,845,180 |
|
|
Acquisitions through business combinations |
190,385 |
|
|
Additions |
447,386 |
|
|
Decommissioning provision additions |
19,120 |
|
|
Dispositions |
(17,649 |
) |
|
Prepaid capital |
2,300 |
|
At December 31, 2012 |
2,486,722 |
|
|
Additions |
578,003 |
|
|
Decommissioning provision additions |
1,439 |
|
|
Dispositions |
- |
|
|
Prepaid capital |
5,081 |
|
At December 31, 2013 |
3,071,245 |
|
Accumulated depletion and depreciation |
|
|
At December 31, 2011 |
(214,546 |
) |
|
Depletion and depreciation |
(172,338 |
) |
|
Dispositions |
146 |
|
At December 31, 2012 |
(386,738 |
) |
|
Depletion and depreciation |
(224,976 |
) |
|
Dispositions |
- |
|
At December 31, 2013 |
(611,714 |
) |
|
|
|
Carrying amount at December 31, 2012 |
2,099,984 |
|
Carrying amount at December 31, 2013 |
2,459,531 |
|
Proceeds received for assets disposed of during 2013 were $nil
(2012 - $21.9 million).
In September 2012, Peyto acquired producing properties for $16.7
million, which were allocated to property, plant and equipment of
$17.4 million and decommissioning liabilities of $0.7 million. The
properties are in Peyto's core area of production. The impact on
revenue and net income is not significant.
During, 2013 Peyto capitalized $7.8 million (2012 - $7.8
million) of general and administrative expense directly
attributable to exploration and development activities.
The Company did not have any indicators of impairment in the
current or prior years.
5. Long-term debt
|
December 31, 2013 |
December 31, 2012 |
Bank
credit facility |
605,000 |
430,000 |
Senior unsecured notes |
270,000 |
150,000 |
Balance, end of the year |
875,000 |
580,000 |
The Company has a syndicated $1.0 billion extendible unsecured
revolving credit facility with a stated term date of April 26,
2015. The bank facility is made up of a $30 million working capital
sub-tranche and a $970 million production line. The facilities are
available on a revolving basis for a two year period. Borrowings
under the facility bear interest at Canadian bank prime (3% at both
December 31, 2013 and 2012) or US base rate, or, at Peyto's option,
Canadian dollar bankers' acceptances or US dollar LIBOR loan rates,
plus applicable margin and stamping fees. The total stamping fees
range between 80 basis points and 225 basis points on Canadian bank
prime and US base rate borrowings and between 180 basis points and
325 basis points on Canadian dollar bankers' acceptance and US
dollar LIBOR borrowings. The undrawn portion of the facility is
subject to a standby fee in the range of 40.5 to 73.13 basis
points.
On January 3, 2012, Peyto issued $100 million of senior secured
notes pursuant to a Note Purchase and Private Shelf agreement. The
notes were issued by way of private placement and rank equally with
Peyto's obligations under its bank facility. The notes have a
coupon rate of 4.39% and mature on January 3, 2019. Interest will
be paid semi-annually in arrears.
On September 6, 2012, Peyto issued $50 million of senior secured
notes pursuant to a Note Purchase and Private Shelf agreement. The
notes were issued by way of private placement and rank equally with
Peyto's obligations under its bank facility. The notes have a
coupon rate of 4.88% and mature on September 6, 2022. Interest will
be paid semi-annually in arrears.
On April 26, 2013, the security on the notes issued on January
3, 2012 and September 6, 2012 was released pursuant to the amended
and restated note purchase and private shelf agreement.
On December 4, 2013, Peyto issued $120 million of senior
unsecured notes pursuant to a Note Purchase agreement. The notes
were issued by way of private placement and rank equally with
Peyto's obligations under its bank facility. The notes have a
coupon rate of 4.50% and mature on December 4, 2020. Interest will
be paid semi-annually in arrears.
Upon the issuance of the senior unsecured notes on April 26,
2013 and December 4, 2013, Peyto is subject to the following
financial covenants as defined in the credit facility and note
purchase agreements:
- Long-term debt plus the average working capital deficiency
(surplus) at the end of the two most recently completed fiscal
quarters adjusted for non-cash items not to exceed 3.0 times
trailing twelve month net income before non-cash items, interest
and income taxes;
- Long-term debt and subordinated debt plus the average working
capital deficiency (surplus) at the end of the two most recently
completed fiscal quarters adjusted for non-cash items not to exceed
4.0 times trailing twelve month net income before non-cash items,
interest and income taxes;
- Trailing twelve months net income before non-cash items,
interest and income taxes to exceed 3.0 times trailing twelve
months interest expense;
- Long-term debt and subordinated debt plus the average working
capital deficiency (surplus) at the end of the two most recently
completed fiscal quarters adjusted for non-cash items not to exceed
55 per cent of the book value of shareholders' equity and long-term
debt and subordinated debt.
Peyto is in compliance with all financial covenants and has no
subordinated debt as at December 31, 2013.
Peyto's total borrowing capacity is $1.27 billion and Peyto's
credit facility is $1.0 billion.
The fair value of all senior notes as at December 31, 2013, is
$269.2 million compared to a carrying value of $270.0 million.
Total interest expense for 2013 was $30.9 million (2012 - $25.4
million) and the average borrowing rate for 2013 was 4.2% (2012 -
4.7%).
6. Decommissioning provision
The Company makes provision for the future cost of
decommissioning wells, pipelines and facilities on a discounted
basis based on the decommissioning of these assets.
The decommissioning provision represents the present value of
the decommissioning costs related to the above infrastructure,
which are expected to be incurred over the economic life of the
assets. The provisions have been based on the Company's internal
estimates on the cost of decommissioning, the discount rate, the
inflation rate and the economic life of the infrastructure.
Assumptions, based on the current economic environment, have been
made which management believes are a reasonable basis upon which to
estimate the future liability. These estimates are reviewed
regularly to take into account any material changes to the
assumptions. However, actual decommissioning costs will ultimately
depend upon the future market prices for the necessary
decommissioning work required which will reflect market conditions
at the relevant time. Furthermore, the timing of the
decommissioning is likely to depend on when production activities
ceases to be economically viable. This in turn will depend and be
directly related to the current and future commodity prices, which
are inherently uncertain.
The following table reconciles the change in decommissioning
provision:
Balance, December 31, 2011 |
38,037 |
|
New or increased provisions |
13,908 |
|
Accretion of discount |
1,044 |
|
Change in discount rate and estimates |
5,212 |
|
Balance, December 31, 2012 |
58,201 |
|
New or increased provisions |
10,216 |
|
Accretion of discount |
1,544 |
|
Change in discount rate and estimates |
(8,777 |
) |
Balance, December 31, 2013 |
61,184 |
|
|
Current |
- |
|
|
Non-current |
61,184 |
|
The Company has estimated the net present value of its total
decommissioning provision to be $61.2 million as at December 31,
2013 ($58.2 million at December 31, 2012) based on a total future
undiscounted liability of $177.8 million ($127.9 million at
December 31, 2012). At December 31, 2013 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 2064. The Bank
of Canada's long term bond rate of 3.24 per cent (2.36 per cent at
December 31, 2012) and an inflation rate of 2.0 per cent (2.0 per
cent at December 31, 2012) were used to calculate the present value
of the decommissioning provision.
7. Equity
Share capital |
Authorized: Unlimited number of voting common
shares |
|
Issued and Outstanding |
|
Common Shares (no par value) |
Number of Common Shares |
Amount $ |
Balance, December 31, 2011 |
137,960,301 |
889,115 |
|
Common shares issued |
4,628,750 |
115,024 |
|
Common shares issued for acquisition |
5,404,007 |
112,187 |
|
Common share issuance costs (net of tax) |
- |
(3,896 |
) |
Common shares issued by private placement |
525,655 |
11,952 |
|
Balance, December 31, 2012 |
148,518,713 |
1,124,382 |
|
Common shares issued by private placement |
240,210 |
5,742 |
|
Common share issuance costs (net of tax) |
- |
(55 |
) |
Balance, December 31, 2013 |
148,758,923 |
1,130,069 |
|
On December 31, 2011 Peyto completed a private placement of
397,235 common shares to employees and consultants for net proceeds
of $9.7 million ($24.52 per share). These common shares were issued
on January 13, 2012.
On March 23, 2012 Peyto completed a private placement of 128,420
common shares to employees and consultants for net proceeds of $2.2
million ($17.22 per share).
On August 14, 2012 Peyto issued 5,404,007 common shares which
were valued at $112.2 million (net of issuance costs) ($20.76 per
share) in relation to the closing of a corporate acquisition (Note
3).
On December 11, 2012, Peyto closed an offering of 4,628,750
common shares at a price of $24.85 per common share, receiving
proceeds of $110.0 million (net of issuance costs).
On December 31, 2012, Peyto completed a private placement of
154,550 common shares to employees and consultants for net proceeds
of $3.5 million ($22.38 per share). These common shares were issued
January 7, 2013.
On March 19, 2013, Peyto completed a private placement of 85,660
common shares to employees and consultants for net proceeds of $2.2
million ($26.65 per share).
Subsequent to December 31, 2013, Peyto closed an offering for
4,720,000 common shares at a price of $34.00 per common share,
receiving net proceeds of $153.6 million. The offering closed on
February 5, 2014.
Shares to be issued
On December 31, 2013, Peyto completed a private placement of
190,525 common shares to employees and consultants for net proceeds
of $6.2 million ($32.78 per share). These common shares were issued
January 8, 2014.
Per share amounts
Earnings per share or unit have been calculated based upon the
weighted average number of common shares outstanding for the year
ended December 31, 2013 of 148,737,654 (2012 - 141,093,829). There
are no dilutive instruments outstanding.
Dividends
During the year ended December 31, 2013, Peyto declared and paid
dividends of $0.88 per common share or $0.06 per common share for
the months of January to April 2013 and $0.08 per common share for
the months of May to December 2013, totaling $130.9 million (2012 -
$0.72 or $0.06 per share per month, $101.6 million).
On January 15, 2014 Peyto declared dividends of $0.08 per common
share paid on February 14, 2014. On February 14, 2014, Peyto
declared dividends of $0.08 per common share to be paid to
shareholders of record on February 28, 2014. These dividends will
be paid on March 14, 2014.
Accumulated other comprehensive income
Comprehensive income consists of earnings and other
comprehensive income ("OCI"). OCI comprises the change in the fair
value of the effective portion of the derivatives used as hedging
items in a cash flow hedge. "Accumulated other comprehensive
income" is an equity category comprised of the cumulative amounts
of OCI.
Accumulated hedging gains
Gains and losses from cash flow hedges are accumulated until
settled. These outstanding hedging contracts are recognized in
earnings on settlement with gains and losses being recognized as a
component of net revenue. Further information on these contracts is
set out in Note 13.
8. Operating expenses
The Company's operating expenses include all costs with respect
to day-to-day well and facility operations. Processing and
gathering recoveries related to jointly controlled assets and third
party natural gas reduce operating expenses.
|
Years ended December 31 |
|
|
2013 |
|
2012 |
|
Field
expenses |
58,963 |
|
46,591 |
|
Processing and gathering recoveries |
(13,728 |
) |
(15,331 |
) |
Total operating expenses |
45,235 |
|
31,260 |
|
9. General and administrative expenses
General and administrative expenses are reduced by operating and
capital overhead recoveries from operated properties.
|
Years ended December 31 |
|
|
2013 |
|
2012 |
|
General and administrative expenses |
14,306 |
|
12,822 |
|
Overhead recoveries |
(9,102 |
) |
(8,976 |
) |
Net general and administrative expenses |
5,204 |
|
3,846 |
|
10. Finance costs
|
Years ended December 31 |
|
2013 |
2012 |
Interest expense |
30,991 |
25,401 |
Accretion of decommissioning provisions |
1,544 |
1,044 |
Total finance costs |
32,535 |
26,445 |
11. Future performance based compensation
The Company awards performance based compensation to employees
annually. The performance based compensation is comprised of
reserve and market value based components.
Reserve based component
The reserves value based component is 4% of the incremental
increase in value, if any, as adjusted to reflect changes in debt,
equity, dividends, general and administrative costs and interest,
of proved producing reserves calculated using a constant price at
December 31 of the current year and a discount rate of 8%.
Market based component
Under the market based component, rights with a three year
vesting period are allocated to employees and key consultants. The
number of rights outstanding at any time is not to exceed 6% of the
total number of common shares outstanding. At December 31 of each
year, all vested rights are automatically cancelled and, if
applicable, paid out in cash. Compensation is calculated as the
number of vested rights multiplied by the total of the market
appreciation (over the price at the date of grant) and associated
dividends of a common share for that period. The 2013 market based
component was based on i) 0.6 million vested rights at an average
grant price of $19.12, average cumulative distributions of $0.72
and a ten day weighted average price of $24.75; ii) 0.07 million
vested rights at an average grant price of $20.63, average
cumulative dividends of $0.48 and a ten day weighted average price
of $22.58 and iii) 1.0 million vested rights at an average grant
price of $22.83, average cumulative distributions of $0.88 and a
ten day weighted average price of $32.27. The 2012 market based
component was based on i) 0.5 million vested rights at an average
grant price of $13.50, average cumulative distributions of $1.44
and a ten day weighted average closing price of $18.83, ii) 0.6
million vested rights at an average grant price of $19.13, average
cumulative distributions of $0.72 and a ten day weighted average
price of $24.75 and iii) 0.07 million vested rights at an average
grant price of $20.63, average cumulative dividends of $0.48 and a
ten day weighted average price of $22.58.
The total amount expensed under these plans was as follows:
($000) |
2013 |
2012 |
Market based compensation |
14,061 |
7,762 |
Reserve based compensation |
2,236 |
4,825 |
Total market and reserves based compensation |
16,297 |
12,587 |
For the future market based component, compensation costs as at
December 31, 2013 were $5.56 million (2012 - $2.82 million
recovery) related to 0.1 million non-vested rights with an average
grant price of $20.63, average cumulative dividends of $0.48 and
2.0 million non-vested rights with an average grant price of $22.83
and average cumulative dividends of $0.88. (2012 - 0.6 million
non-vested rights with an average grant price of $19.13 and 0.1
million non-vested rights with an average grant price of $20.63
were a recovery of $2.8 million). The cumulative provision for
future performance based compensation as at December 31, 2013 was
$8.3 million (2012 - $2.7 million).
The fair values were calculated using a Black-Scholes valuation
model. The principal inputs to the option valuation model were:
|
December 31 2013 |
|
December 31 2012 |
|
Share
price |
$ |
32.27 |
|
$ |
22.58 |
|
Exercise price |
$ |
19.91 - $21.70 |
|
$ |
18.41 - $19.91 |
|
Expected volatility |
|
0 |
% |
|
0 |
% |
Option life |
|
1
- 2 years |
|
|
1
- 2 years |
|
Dividend yield |
|
0 |
% |
|
0 |
% |
Risk-free interest rate |
|
1.13 |
% |
|
1.08 |
% |
Subsequent to December 31, 2013, 3.2 million rights were granted
at a price of $32.78 to be valued at the ten day weighted average
market price at December 31, 2013 and vesting one third on each of
December 31, 2014, December 31, 2015 and December 31, 2016.
12. Income taxes
($000) |
2013 |
|
2012 |
|
Earnings before income taxes |
189,363 |
|
130,093 |
|
Statutory income tax rate |
25.00 |
% |
25.00 |
% |
Expected income taxes |
47,341 |
|
32,523 |
|
Increase (decrease) in income taxes from: |
|
|
|
|
|
True-up tax pools |
(443 |
) |
1,634 |
|
|
Resolution of reassessment and other |
(162 |
) |
1,985 |
|
Total income tax expense |
46,736 |
|
36,142 |
|
|
|
|
|
|
Deferred income tax expense |
46,736 |
|
34,274 |
|
Current income tax expense |
- |
|
1,868 |
|
Total income tax expense |
46,736 |
|
36,142 |
|
Differences between tax base and reported amounts for
depreciable assets |
(249,382 |
) |
(207,805 |
) |
Derivative financial instruments |
7,947 |
|
1,930 |
|
Share issuance costs |
1,826 |
|
(3,095 |
) |
Future performance based bonuses |
2,075 |
|
(684 |
) |
Provision for decommission provision |
15,296 |
|
(14,550 |
) |
Cumulative eligible capital |
6,139 |
|
(6,599 |
) |
Attributable crown royalty income carryforward |
- |
|
- |
|
Tax loss carry-forwards recognized |
5,017 |
|
(10,566 |
) |
Deferred income taxes |
(211,082 |
) |
(174,241 |
) |
At December 31, 2013 the Company has tax pools of approximately
$1,467.1 million (2012 - $1,288.0 million) available for deduction
against future income. The Company has approximately $19.7 million
in loss carry-forwards (2012 - $42.1 million) available to reduce
future taxable income.
Canada Revenue Agency ("CRA") conducted an audit of
restructuring costs incurred in the 2003 trust conversion. On
September 25, 2008, the CRA reassessed on the basis that $41
million of these costs were not deductible and treated them as an
eligible capital amount. The Company filed a notice of objection
and the CRA confirmed the reassessment. Examinations for discovery
have been completed. The Tax Court of Canada had agreed to both
parties' request to hold the Company's appeal in abeyance pending a
decision of the Supreme Court of Canada to hear another taxpayer's
appeal. The other appeal raised issues that are similar in
principle to those raised in the Company's appeal. As the other
taxpayer's appeal was unsuccessful with the Federal Court of
Appeal, in 2011, the Company expensed the income tax of $4.9
million and interest charges of $2.2 million assessed and paid in
2008. Subsequently, the Alberta Government reassessed the same time
period resulting in income taxes payable of $1.8 million and
interest charges of $1.4 million paid in 2013.
13. Financial instruments
Financial instrument classification and measurement
Financial instruments of the Company carried on the balance
sheet are carried at amortized cost with the exception of cash
derivative financial 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,
2013.
The fair value of the Company's cash and derivative financial
instruments, are quoted in active markets. The Company classifies
the fair value of these transactions according to the following
hierarchy.
- Level 1 - quoted prices in active markets for identical
financial instruments.
- Level 2 - quoted prices for similar instruments in active
markets; quoted prices for identical or similar instruments in
markets that are not active; and model-derived valuations in which
all significant inputs and significant and significant value
drivers are observable in active markets.
- Level 3 - valuations derived from valuation techniques in which
one or more significant inputs or significant value drivers are
unobservable.
The Company's cash and financial derivative instruments have
been assessed on the fair value hierarchy described above and
classified as Level 1.
Fair values of financial assets and liabilities
The Company's financial instruments include cash, accounts
receivable, derivative financial instruments, due from private
placement, current liabilities, provision for future performance
based compensation and long term debt. At December 31, 2013 and
2012, cash and derivative financial instruments, are carried at
fair value. Accounts receivable, due from private placement,
current liabilities and provision for future performance based
compensation approximate their fair value due to their short term
nature. The carrying value of the long term debt approximates its
fair value due to the floating rate of interest charged under the
credit facility.
Market risk
Market risk is the risk that changes in market prices will
affect the Company's earnings or the value of its financial
instruments. Market risk is comprised of commodity price risk and
interest rate risk. The objective of market risk management is to
manage and control exposures within acceptable limits, while
maximizing returns. The Company's objectives, processes and
policies for managing market risks have not changed from the
previous year.
Commodity price risk management
The Company is a party to certain derivative financial
instruments, including fixed price contracts. The Company enters
into these contracts with well-established counterparties for the
purpose of protecting a portion of its future earnings and cash
flows from operations from the volatility of petroleum and natural
gas prices. The Company believes the derivative financial
instruments are effective as hedges, both at inception and over the
term of the instrument, as the term and notional amount do not
exceed the Company's firm commitment or forecasted transactions and
the underlying basis of the instruments correlate highly with the
Company's exposure.
Following is a summary of all risk management contracts in place
as at December 31, 2013:
Propane Period Hedged |
Type |
Monthly Volume |
Price (USD) |
January 1, 2014 to March 31, 2014 |
Fixed
Price |
4,000
bbl |
$37.80/bbl |
January 1, 2014 to March 31, 2014 |
Fixed
Price |
4,000
bbl |
$36.54/bbl |
January 1, 2014 to March 31, 2014 |
Fixed
Price |
4,000
bbl |
$39.354/bbl |
January 1, 2014 to March 31, 2014 |
Fixed
Price |
4,000
bbl |
$41.37/bbl |
January 1, 2014 to March 31, 2014 |
Fixed
Price |
4,000
bbl |
$44.94/bbl |
January 1, 2014 to March 31, 2014 |
Fixed
Price |
4,000
bbl |
$49.455/bbl |
January 1, 2014 to December 31, 2014 |
Fixed
Price |
4,000
bbl |
$35.70/bbl |
January 1, 2014 to December 31, 2014 |
Fixed
Price |
4,000
bbl |
$37.485/bbl |
April
1, 2014 to September 30, 2014 |
Fixed
Price |
4,000
bbl |
$41.79/bbl |
April
1, 2014 to September 30, 2014 |
Fixed
Price |
4,000
bbl |
$42.63/bbl |
April
1, 2014 to September 30, 2014 |
Fixed
Price |
4,000
bbl |
$44.31/bbl |
October 1, 2014 to December 31, 2014 |
Fixed Price |
4,000 bbl |
$42.84/bbl |
Natural Gas Period Hedged |
Type |
Daily Volume |
Price (CAD) |
April
1, 2012 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.00/GJ |
August 1, 2012 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.00/GJ |
August 1, 2012 to October 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.10/GJ |
November 1, 2012 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$2.81/GJ |
November 1, 2012 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.00/GJ |
November 1, 2012 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.05/GJ |
November 1, 2012 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.02/GJ |
November 1, 2012 to October 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.0575/GJ |
January 1, 2013 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.00/GJ |
January 1, 2013 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.02/GJ |
April
1, 2013 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.105/GJ |
April
1, 2013 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.53/GJ |
April
1, 2013 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.45/GJ |
April
1, 2013 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.50/GJ |
April
1, 2013 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.08/GJ |
April
1, 2013 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.17GJ |
April
1, 2013 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.10/GJ |
April
1, 2013 to October 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.25/GJ |
April
1, 2013 to October 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.30/GJ |
April
1, 2013 to October 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.33/GJ |
April
1, 2013 to October 31, 2014 |
Fixed
Price |
7,500
GJ |
$3.20/GJ |
April
1, 2013 to October 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.22/GJ |
April
1, 2013 to October 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.20/GJ |
April
1, 2013 to October 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.1925/GJ |
April
1, 2013 to October 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.25/GJ |
April
1, 2013 to October 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.30/GJ |
August 1, 2013 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.55/GJ |
November 1, 2013 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.71/GJ |
November 1, 2013 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.76/GJ |
November 1, 2013 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.86/GJ |
November 1, 2013 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$4.00/GJ |
November 1, 2013 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.90/GJ |
November 1, 2013 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.52/GJ |
November 1, 2013 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.1025/GJ |
November 1, 2013 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.245/GJ |
November 1, 2013 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.45/GJ |
November 1, 2013 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.3075/GJ |
November 1, 2013 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.25/GJ |
November 1, 2013 to October 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.50/GJ |
November 1, 2013 to October 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.53/GJ |
November 1, 2013 to March 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.6025/GJ |
December 1, 2013 to March 31,2014 |
Fixed
Price |
5,000
GJ |
$3.50/GJ |
January 1, 2014 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.295/GJ |
January 1, 2014 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.35/GJ |
January 1, 2014 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.51/GJ |
January 1, 2014 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.60/GJ |
January 1, 2014 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.65/GJ |
February 1, 2014 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.70/GJ |
February 1, 2014 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.80/GJ |
April
1, 2014 to October 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.505/GJ |
April
1, 2014 to October 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.555/GJ |
April
1, 2014 to October 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.48/GJ |
April
1, 2014 to October 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.335/GJ |
April
1, 2014 to October 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.10/GJ |
April
1, 2014 to March 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.82/GJ |
April
1, 2014 to March 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.44/GJ |
April
1, 2014 to March 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.52/GJ |
April
1, 2014 to March 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.4725/GJ |
April
1, 2014 to March 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.525/GJ |
April
1, 2014 to March 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.60/GJ |
April
1, 2014 to March 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.27/GJ |
April
1, 2014 to March 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.41/GJ |
April
1, 2014 to March 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.5575/GJ |
April
1, 2014 to March 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.465/GJ |
April
1, 2014 to March 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.43/GJ |
April
1, 2014 to March 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.54/GJ |
April
1, 2014 to March 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.50/GJ |
April
1, 2014 to March 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.25/GJ |
April
1, 2014 to March 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.25/GJ |
April
1, 2014 to March 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.23/GJ |
April
1, 2014 to March 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.23/GJ |
April
1, 2014 to March 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.23/GJ |
April
1, 2014 to March 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.31/GJ |
April
1, 2014 to March 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.3525/GJ |
April
1, 2014 to March 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.40/GJ |
April
1, 2014 to March 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.49/GJ |
April
1, 2014 to March 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.54/GJ |
April
1, 2014 to March 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.61/GJ |
April
1, 2014 to March 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.70/GJ |
April
1, 2014 to March 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.75/GJ |
November 1, 2014 to March 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.81/GJ |
April
1, 2015 to October 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.285/GJ |
April
1, 2015 to October 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.30/GJ |
April
1, 2015 to October 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.35/GJ |
April 1, 2015 to October 31, 2015 |
Fixed Price |
5,000 GJ |
$3.40/GJ |
As at December 31, 2013, Peyto had committed to the future sale
of 252,000 barrels of natural gas liquids at an average price of
$42.67 CAD ($40.12 USD) per barrel and 96,070,000 gigajoules (GJ)
of natural gas at an average price of $3.40 per GJ or $3.91 per
mcf. Had these contracts been closed on December 31, 2013, Peyto
would have realized a loss in the amount of $31.7 million. If the
AECO gas price on December 31, 2013 were to increase by $1/GJ, the
unrealized loss would increase by approximately $96.1 million. An
opposite change in commodity prices rates would result in an
opposite impact on other comprehensive income.
Subsequent to December 31, 2013 Peyto entered into the following
contracts:
Propane Period Hedged |
Type |
Monthly Volume |
Price (USD) |
April 1, 2014 to September 30, 2014 |
Fixed Price |
4,000 bbl |
$46.20/bbl |
Natural Gas Period Hedged |
Type |
Daily Volume |
Price (CAD) |
February 1, 2014 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.90/GJ |
February 1, 2014 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.85/GJ |
March
1, 2014 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$4.15/GJ |
March
1, 2014 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$4.24/GJ |
March
1, 2014 to March 31, 2014 |
Fixed
Price |
5,000
GJ |
$5.10/GJ |
April
1, 2014 to October 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.80/GJ |
April
1, 2014 to October 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.825/GJ |
April
1, 2014 to October 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.95/GJ |
April
1, 2014 to October 31, 2014 |
Fixed
Price |
5,000
GJ |
$3.98/GJ |
April
1, 2014 to October 31, 2014 |
Fixed
Price |
5,000
GJ |
$4.07/GJ |
April
1, 2014 to October 31, 2014 |
Fixed
Price |
5,000
GJ |
$4.32/GJ |
April
1, 2014 to October 31, 2014 |
Fixed
Price |
5,000
GJ |
$4.35/GJ |
April
1, 2014 to October 31, 2014 |
Fixed
Price |
5,000
GJ |
$4.55/GJ |
April
1, 2014 to March 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.81/GJ |
April
1, 2014 to March 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.83/GJ |
November 1, 2014 to October 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.95/GJ |
November 1, 2014 to October 31, 2015 |
Fixed
Price |
5,000
GJ |
$4.05/GJ |
November 1, 2014 to October 31, 2015 |
Fixed
Price |
5,000
GJ |
$4.12/GJ |
November 1, 2014 to October 31, 2015 |
Fixed
Price |
5,000
GJ |
$4.20/GJ |
November 1, 2014 to October 31, 2015 |
Fixed
Price |
5,000
GJ |
$4.44/GJ |
November 1, 2014 to October 31, 2015 |
Fixed
Price |
5,000
GJ |
$4.585/GJ |
November 1, 2014 to October 31, 2015 |
Fixed
Price |
5,000
GJ |
$4.78/GJ |
April
1, 2015 to October 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.47/GJ |
April
1, 2015 to October 31, 2015 |
Fixed
Price |
5,000
GJ |
$3.48/GJ |
April 1, 2015 to October 31, 2015 |
Fixed Price |
5,000 GJ |
$3.52/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, 2013
would decrease by $5.8 million. An opposite change in interest
rates would 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. Credit limits exceeding
$2,000,000 per month are not granted to non-investment grade
counterparties unless the Company receives either i) a parental
guarantee from an investment grade parent; or ii) an irrevocable
letter of credit for two months revenue. 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, 2013, approximately 62% was received from five
companies (15%, 13%, 13%, 11%, and 10%) (December 31, 2012 - 14%,
one company). Of the Company's accounts receivable at December 31,
2013, approximately 61% was receivable from five companies (14%,
14%, 11%, 11%, and 11%) (December 31, 2012 - 14%, one company). The
maximum exposure to credit risk is represented by the carrying
amount on the balance sheet. There are no material financial assets
that the Company considers past due and no accounts have been
written off.
The Company may be exposed to certain losses in the event of
non-performance by counterparties to commodity price contracts. The
Company mitigates this risk by entering into transactions with
counterparties that have investment grade credit ratings.
Counterparties to financial instruments expose the Company to
credit losses in the event of non-performance. Counterparties for
derivative instrument transactions are limited to high
credit-quality financial institutions, which are all members of our
syndicated credit facility.
The Company assesses quarterly if there should be any impairment
of financial assets. At December 31, 2013, 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, 2013:
|
< 1 Year |
1-2 Years |
3-5 Years |
Thereafter |
Accounts payable and accrued liabilities |
155,265 |
- |
- |
- |
Dividends payable |
11,901 |
- |
- |
- |
Provision for future market and reserves based bonus |
5,100 |
3,200 |
- |
- |
Current taxes payable |
- |
- |
- |
- |
Long-term debt(1) |
- |
605,000 |
- |
- |
Unsecured senior notes |
- |
- |
- |
270,000 |
(1) Revolving credit facility renewed annually (see Note
5)
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 equity, debt and working capital. To
maintain or adjust the capital structure, the Company may from time
to time, issue common shares, raise debt, adjust its capital
spending or change dividends paid to manage its current and
projected debt levels. The Company monitors capital based on the
following measures: current and projected debt to earnings before
interest, taxes, depreciation, depletion and amortization
("EBITDA") ratios, payout ratios and net debt levels. To facilitate
the management of these ratios, the Company prepares annual
budgets, which are updated depending on varying factors such as
general market conditions and successful capital deployment.
Currently, all ratios are within acceptable parameters. The annual
budget is approved by the Board of Directors.
There were no changes in the Company's approach to capital
management from the previous year.
|
December 31 2013 |
December 31 2012 |
Equity |
1,200,638 |
1,210,067 |
Long-term debt |
875,000 |
580,000 |
Working capital (surplus) deficit |
103,247 |
74,884 |
|
2,178,885 |
1,864,951 |
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. For the year
ended December 31, 2013, legal fees totaled $0.7 million (2012 -
$1.2 million). As at December 31, 2013, an amount due to this firm
of $0.7 million was included in accounts payable (2012 - $1.2
million).
The Company has determined that the key management personnel
consists of 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 $1.4 million is included in general and administrative
expenses and $6.5 million in market and reserves based bonus
relating to key management personnel for the year 2013 (2012 - $1.3
million in general and administrative and $5.0 million in market
and reserves based bonus).
15. Commitments
Peyto has contractual obligations and commitments as
follows:
|
2014 |
2015 |
2016 |
2017 |
2018 |
Thereafter |
Note repayment(1) |
- |
- |
- |
- |
- |
270,000 |
Interest payments(2) |
12,230 |
12,230 |
12,230 |
12,230 |
12,230 |
22,755 |
Transportation commitments |
18,350 |
16,354 |
12,276 |
8,414 |
6,175 |
4,873 |
Operating leases |
2,412 |
2,380 |
1,863 |
1,654 |
1,295 |
10,356 |
Total |
32,992 |
30,964 |
26,369 |
22,298 |
19,700 |
307,984 |
(1) Long-term debt repayment on senior unsecured notes |
(2) Fixed interest payments on senior unsecured notes |
16. Contingencies
On October 31, 2013, Peyto was named as a party to a statement
of claim received with respect to transactions between Poseidon
Concepts Corp. and Open Range Energy Corp. The allegations
contained in the claim are based on factual matters that
pre-existed Peyto's involvement with New Open Range which makes
them difficult to assess at this time. However, Peyto intends to
aggressively protect its interests and the interests of its
shareholders and will seek all available legal remedies in
defending the action. Management continues to assess the nature of
this claim, in conjunction with their legal advisors.
Officers
|
Darren Gee President and Chief Executive Officer |
Tim
Louie Vice President, Land |
|
|
|
|
Scott
Robinson Executive Vice President and Chief Operating Officer |
David
Thomas Vice President, Exploration |
|
|
|
|
Kathy
Turgeon Vice President, Finance and Chief Financial Officer |
Jean-Paul Lachance Vice President, Exploitation |
|
|
|
|
Stephen Chetner Corporate Secretary |
|
|
|
|
Directors |
|
Don Gray, Chairman |
|
Stephen Chetner |
|
Brian Davis |
|
Michael MacBean, Lead Independent
Director |
|
Darren Gee |
|
Gregory Fletcher |
|
Scott Robinson |
|
Auditors |
|
Deloitte LLP |
|
Solicitors |
|
Burnet, Duckworth & Palmer LLP |
|
Bankers |
|
Bank of Montreal |
|
Union Bank, Canada Branch |
|
Royal Bank of Canada |
|
Canadian Imperial Bank of Commerce |
|
The Toronto-Dominion Bank |
|
Bank of Nova Scotia |
|
HSBC Bank Canada |
|
Alberta Treasury Branches |
|
Canadian Western Bank |
|
Transfer Agent |
|
Valiant Trust Company |
|
Head Office |
|
1500, 250 - 2nd Street SW |
|
Calgary, AB |
|
T2P 0C1 |
|
Phone: 403.261.6081 |
|
Fax: 403.451.4100 |
|
Web: www.peyto.com |
|
Stock Listing Symbol: PEY.TO |
|
Toronto Stock Exchance |
Peyto Exploration & Development
Corp.403.261.6081403.451.4100www.peyto.com
Peyto Exploration and De... (TSX:PEY)
Gráfico Histórico do Ativo
De Abr 2024 até Mai 2024
Peyto Exploration and De... (TSX:PEY)
Gráfico Histórico do Ativo
De Mai 2023 até Mai 2024