Peyto Exploration & Development Corp.
(TSX:PEY) (“Peyto” or the “Company”) is pleased to report operating
and financial results for the fourth quarter and 2017 fiscal year.
Peyto achieved a 75% operating margin1 and a 23% profit margin2 in
2017, while also generating its second highest all-time revenue and
funds from operations. Over Peyto’s 19 years, the Company has
invested $5.7 billion of capital to profitably grow production and
reserves per share while generating over $19/share in earnings and
paying over $18/share in distributions and dividends. With average
Return on Capital Employed (“ROCE”) of 16% and Return on Equity
(“ROE”) of 30%, Peyto has been one of Canada’s most profitable
natural gas producers. Highlights for the fourth quarter and full
year 2017 included:
- Production per share up 4% – Average annual
production increased 6%, or 4% per share, to 616 MMcfe/d (102,614
boe/d) in 2017 up from 582 MMcfe/d (96,975 boe/d) in 2016. Q4 2017
production was up 8%, also 8% per share, from Q4 2016 to 659
MMcfe/d (109,793 boe/d). Production deferrals due to low gas price
in Q3 and Q4 reduced 2017 annual production by 950 boe/d.
- Reserves per share up 9% – Producing reserves
increased 11% to 1.6 TCFe (275 mmboes), up 9% per share, while
total P+P reserves increased 10% to 4.3 TCFe (722 mmboes), up 9%
per share.
- Total Cash costs $0.83/Mcfe ($4.99/boe) – Cash
costs of $0.68Mcfe, before royalties of $0.15/Mcfe, included
operating costs of $0.27/Mcfe, transportation of $0.16/Mcfe,
G&A of $0.04/Mcfe and interest expense of $0.21/Mcfe. Total
cash costs in 2017 were up 8% from 2016 due to higher royalties and
interest rates. Total 2017 cash costs combined with a realized
price of $3.38/Mcfe ($20.32/boe), resulting in a cash netback of
$2.55/Mcfe ($15.32/boe) or a 75% operating margin. Q4 2017 cash
costs were $0.83/Mcfe ($4.96/boe), with a realized price of
$3.50/Mcfe ($20.97/boe) and cash netback of $2.67/Mcfe
($16.01/boe).
- Funds from operations(3) per share of $3.48 –
Annual Funds from Operations (“FFO”) of $574 million, or
$3.48/share, was up 11% (10% per share) from $515 million in 2016
as a result of a 6% increase in production combined with a 7%
increase in realized commodity prices. Q4 2017 FFO was $162 million
or $0.98/share compared to $145 million, or $0.88/share, in Q4
2016.
- Capital investments of $521 million – A total
of $521 million was invested in the drilling of 142 gross (138 net)
wells that contributed 47,000 boe/d of incremental production at
year end for a cost of $11,000/boe/d. This was consistent with 2016
and is inclusive of $78 million of land, seismic, facility costs
and $443 million of well-related costs.
- PDP FD&A lowest since 2003 – All in cost
to develop new producing reserves was $1.36/Mcfe ($8.13/boe), down
6% from 2016, while the field netback for 2017 averaged $2.55/Mcfe
($15.32/boe) resulting in a recycle ratio of 1.9 times. The Company
replaced 171% of production with new producing reserves at the
lowest cost since 2003.
- Earnings per share of $1.07 – Annual earnings
of $177 million in 2017 were up 57% (55% per share) from $112
million in 2016 due to the increase in cashflow combined with
reduced finding costs. Q4 2017 earnings of $52 million
($0.31/share) equated to a profit margin of 24% of revenue.
Earnings generated in 2017 represent the 18th consecutive year of
recorded profits totaling over $2.33 billion, while cumulative
dividends/distributions to shareholders have totaled $2.29
billion.
2017 in Review
The year 2017 was a year of even greater gas
price volatility than 2016. Daily Alberta natural gas prices swung
wildly from highs of over $4/GJ to, at times, less than zero. The
price at which gas could be sold into the future fell by as much as
50%. Much of this volatility was due to a surprising change in
NGTL’s service priorities in combination with a late surge of WCSB
supply without incremental capacity to access export markets. This
has created significant near-term uncertainty for the future of gas
prices in the WCSB. Peyto’s hedging practice of forward selling
large portions of its natural gas in order to smooth out gas price
volatility allowed the Company to continue with mostly steady
production operations and to conduct its most active year ever,
drilling a record 142 horizontal wells in its liquids-rich, gas
resource plays. Several large pipeline projects were completed in
the year which expanded Peyto’s owned and operated infrastructure
including main gas gathering lines in Brazeau and Whitehorse as
well as an integrated liquids storage and gathering pipeline which
connected four of the six Greater Sundance gas plants. This liquids
pipeline resulted in significantly less trucking which reduced
emissions, improved NGL price realizations, and contributed to the
18% annual increase in liquids pricing. Peyto added 88 sections of
new land in 2017, almost twice that acquired in 2016, for an
average of $253/acre. Although, the Company internally identifies
numerous locations per new section of land acquired, these
locations have yet to be recognized in the annual reserves
evaluation. The solid returns generated on the 2017 capital program
drove an 8% ROCE, 11% ROE and 55% increase in earnings per
share.
|
Three Months Ended Dec 31 |
% |
Twelve Months Ended Dec 31 |
% |
|
2017 |
2016 |
Change |
2017 |
2016 |
Change |
Operations |
|
|
|
|
|
|
Production |
|
|
|
|
|
|
Natural gas
(mcf/d) |
595,885 |
556,975 |
7 |
% |
559,663 |
537,111 |
4 |
% |
Oil & NGLs
(bbl/d) |
10,479 |
8,938 |
17 |
% |
9,337 |
7,457 |
25 |
% |
Thousand cubic
feet equivalent (Mcfe/d @ 1:6) |
658,759 |
610,602 |
8 |
% |
615,684 |
581,852 |
6 |
% |
Barrels of oil
equivalent (boe/d @ 6:1) |
109,793 |
101,767 |
8 |
% |
102,614 |
96,975 |
6 |
% |
Production per million
common shares (boe/d)* |
666 |
618 |
8 |
% |
622 |
597 |
4 |
% |
Product prices |
|
|
|
|
|
|
Natural gas
($/mcf) |
2.87 |
2.98 |
-4 |
% |
2.89 |
2.89 |
- |
|
Oil & NGLs
($/bbl) |
56.52 |
45.09 |
25 |
% |
50.02 |
40.30 |
24 |
% |
Operating expenses
($/Mcfe) |
0.28 |
0.26 |
8 |
% |
0.27 |
0.25 |
8 |
% |
Transportation
($/Mcfe) |
0.16 |
0.16 |
- |
|
0.16 |
0.16 |
- |
|
Field netback
($/Mcfe) |
2.91 |
2.78 |
5 |
% |
2.80 |
2.64 |
6 |
% |
General &
administrative expenses ($/Mcfe) |
0.03 |
0.03 |
- |
|
0.04 |
0.04 |
- |
|
Interest expense
($/Mcfe) |
0.21 |
0.18 |
17 |
% |
0.21 |
0.18 |
17 |
% |
Financial
($000, except per share*) |
|
|
|
|
|
|
Revenue |
211,799 |
189,951 |
12 |
% |
760,956 |
678,388 |
12 |
% |
Royalties |
9,232 |
10,089 |
-8 |
% |
34,104 |
28,330 |
20 |
% |
Funds from
operations |
161,672 |
144,593 |
12 |
% |
573,721 |
514,593 |
11 |
% |
Funds from operations
per share |
0.98 |
0.88 |
11 |
% |
3.48 |
3.17 |
10 |
% |
Total dividends |
54,408 |
54,328 |
- |
|
217,612 |
214,911 |
1 |
% |
Total dividends per
share |
0.33 |
0.33 |
- |
|
1.32 |
1.32 |
- |
|
Payout ratio
(%) |
34 |
38 |
-11 |
% |
38 |
42 |
-10 |
% |
Earnings |
51,547 |
38,489 |
34 |
% |
176,575 |
112,348 |
57 |
% |
Earnings per share |
0.31 |
0.23 |
34 |
% |
1.07 |
0.69 |
55 |
% |
Capital
expenditures |
134,411 |
129,407 |
4 |
% |
521,210 |
469,375 |
11 |
% |
Weighted average common
shares outstanding |
164,874,175 |
164,630,168 |
- |
|
164,856,042 |
162,573,515 |
1 |
% |
As at December
31 |
|
|
|
|
|
|
End of period shares
outstanding (includes shares to be issued) |
|
|
|
164,874,175 |
164,776,923 |
- |
|
Net debt |
|
|
|
1,327,440 |
1,131,052 |
17 |
% |
Shareholders'
equity |
|
|
|
1,722,978 |
1,540,934 |
12 |
% |
Total assets |
|
|
|
3,844,714 |
3,463,089 |
11 |
% |
*all per
share amounts using weighted average common shares outstanding |
|
|
|
|
|
Three Months Ended Dec 31 |
Twelve Months Ended Dec 31 |
($000
except per share) |
2017 |
|
2016 |
|
2017 |
2016 |
|
Cash flows from
operating activities |
143,568 |
|
138,329 |
|
535,344 |
508,629 |
|
Change in
non-cash working capital |
6,444 |
|
(4,012 |
) |
20,381 |
(24,661 |
) |
Change in
provision for performance based compensation |
(4,024 |
) |
(15,494 |
) |
2,312 |
4,855 |
|
Performance based
compensation |
15,684 |
|
25,770 |
|
15,684 |
25,770 |
|
Funds from operations |
161,672 |
|
144,593 |
|
573,721 |
514,593 |
|
Funds
from operations per share |
0.98 |
|
0.88 |
|
3.48 |
3.17 |
|
(1) Operating Margin is defined as Funds from Operations divided
by Revenue before Royalties but including realized hedging gains
(losses).(2) Profit Margin is defined as Net Earnings for the year
divided by Revenue before Royalties but including realized hedging
gains (losses).Natural gas volumes recorded in thousand cubic feet
(Mcf) are converted to barrels of oil equivalent (boe) using the
ratio of six (6) thousand cubic feet to one (1) barrel of oil
(bbl). Natural gas liquids and oil volumes in barrel of oil
(bbl) are converted to thousand cubic feet equivalent (Mcfe) using
a ratio of one (1) barrel of oil to six (6) thousand cubic
feet. This could be misleading if used in isolation as it is
based on an energy equivalency conversion method primarily applied
at the burner tip and does not represent a value equivalency at the
wellhead.(3) Funds from operations - Management uses funds from
operations to analyze the operating performance of its energy
assets. In order to facilitate comparative analysis, funds
from operations is defined throughout this report as earnings
before performance based compensation, non‑cash and non‑recurring
expenses. Management believes that funds from operations is
an important parameter to measure the value of an asset when
combined with reserve life. Funds from operations is not a
measure recognized by Canadian generally accepted accounting
principles ("GAAP") and does not have a standardized meaning
prescribed by GAAP. Therefore, funds from operations, as
defined by Peyto, may not be comparable to similar measures
presented by other issuers, and investors are cautioned that funds
from operations should not be construed as an alternative to net
earnings, cash flow from operating activities or other measures of
financial performance calculated in accordance with GAAP.
Funds from operations cannot be assured and future dividends may
vary.
The Peyto Strategy
For the past 19 years, the Peyto strategy has
focused on maximizing the returns on shareholders’ capital by
deploying that capital into the profitable development of long
life, low cost, and low risk natural gas resource plays. This
strategy of maximizing returns does not end in the field with just
the efficient execution of exploration and production operations
but continues on to the head office where the management of
corporate costs, including the cost of capital, must be controlled
to ensure true returns are ultimately enjoyed. Alignment of goals
between what is good for the company and its employees and what is
good for all stakeholders is critical to ensuring that the greatest
returns are achieved. Evidence of the success Peyto has had
deploying this strategy, through the commodity price cycle, is
illustrated in the following table.
($/Mcfe) |
|
2007 |
|
|
2008 |
|
|
2009 |
|
|
2010 |
|
|
2011 |
|
|
2012 |
|
|
2013 |
|
|
2014 |
|
|
2015 |
|
|
2016 |
|
|
2017 |
|
|
|
19 Year Wt. Avg. |
Sales Price |
$8.93 |
|
$9.54 |
|
$6.75 |
|
$6.15 |
|
$5.47 |
|
$4.21 |
|
$4.43 |
|
$5.04 |
|
$3.83 |
|
$3.18 |
|
$3.38 |
|
|
|
$4.99 |
|
All cash costs but royalties2 |
($1.19 |
) |
($1.19 |
) |
($1.12 |
) |
($0.99 |
) |
($0.82 |
) |
($0.73 |
) |
($0.75 |
) |
($0.71 |
) |
($0.67 |
) |
($0.63 |
) |
($0.68 |
) |
|
|
($0.74 |
) |
Capital costs1 |
($2.11 |
) |
($2.88 |
) |
($2.26 |
) |
($2.10 |
) |
($2.12 |
) |
($2.22 |
) |
($2.35 |
) |
($2.25 |
) |
($1.64 |
) |
($1.44 |
) |
($1.36 |
) |
|
|
($1.83 |
) |
Profits |
$5.63 |
|
$5.47 |
|
$3.37 |
|
$3.06 |
|
$2.53 |
|
$1.26 |
|
$1.33 |
|
$2.08 |
|
$1.52 |
|
$1.12 |
|
$1.34 |
|
|
|
$2.42 |
|
|
|
63 |
% |
|
57 |
% |
|
50 |
% |
|
50 |
% |
|
46 |
% |
|
30 |
% |
|
30 |
% |
|
41 |
% |
|
40 |
% |
|
35 |
% |
|
40 |
% |
|
|
|
49 |
% |
Royalty Owners |
$1.56 |
|
$1.82 |
|
$0.63 |
|
$0.64 |
|
$0.53 |
|
$0.32 |
|
$0.31 |
|
$0.37 |
|
$0.14 |
|
$0.13 |
|
$0.15 |
|
|
|
$0.56 |
|
Shareholders |
$4.07 |
|
$3.65 |
|
$2.74 |
|
$2.42 |
|
$2.00 |
|
$0.94 |
|
$1.02 |
|
$1.71 |
|
$1.38 |
|
$0.99 |
|
$1.19 |
|
|
|
$1.86 |
|
Div./Dist. paid |
$3.92 |
|
$4.25 |
|
$4.03 |
|
$3.37 |
|
$1.24 |
|
$1.04 |
|
$1.01 |
|
$1.05 |
|
$1.11 |
|
$1.01 |
|
$0.97 |
|
|
|
$1.55 |
|
1. Capital costs to develop new producing reserves is the PDP
FD&A2. Cash costs not including royalties but including
Operating costs, Transportation, G&A and Interest.
The consistency and repeatability of Peyto’s
operational execution in the field, combined with strict cost
control in all aspects of its business has resulted in nearly 50%
of the average sales price being retained in profit. This healthy
margin of profit (as defined above), which benefits both royalty
owners and shareholders, has been preserved despite a greater than
60% drop in commodity prices from a decade ago. Out of that profit,
royalty owners have received approximately 25%, while shareholders,
whose capital has been at risk, have received the balance. This
margin is what has and will continue to help insulate Peyto and its
stakeholders from future volatility in commodity prices.
Capital Expenditures
Peyto drilled 135 gross (131 net) horizontal and
7 gross (7 net) vertical wells in 2017 for a capital investment of
$257 million. The Company completed 142 gross (138 net) wells for
$134 million and invested $53 million in the wellsite equipment and
pipeline connections to bring these wells on production. Both
drilling and completion costs on a per-well and per-meter basis
were higher than the previous year mostly due to a greater
percentage of wells being located in Brazeau, which has less
surface infrastructure (roads and existing padsites) already in
place. An average of 12.2 frac stages were pumped per well, up from
10.8 stages in 2016, contributing to the higher completion cost per
meter.
The table below outlines the past seven years of
average horizontal drilling and completion costs.
|
|
2010 |
|
2011 |
|
2012 |
|
2013 |
|
2014 |
|
2015 |
|
2016 |
|
2017 |
Gross Spuds |
|
52 |
|
70 |
|
86 |
|
99 |
|
123 |
|
140 |
|
126 |
|
135 |
Length (m) |
|
3,762 |
|
3,903 |
|
4,017 |
|
4,179 |
|
4,251 |
|
4,309 |
|
4,197 |
|
4,229 |
|
|
|
|
|
|
|
|
|
Drilling ($MM) |
$ |
2.763 |
$ |
2.823 |
$ |
2.789 |
$ |
2.720 |
$ |
2.660 |
$ |
2,159 |
$ |
1,818 |
$ |
1,902 |
$ per meter |
$ |
734 |
$ |
723 |
$ |
694 |
$ |
651 |
$ |
626 |
$ |
501 |
$ |
433 |
$ |
450 |
|
|
|
|
|
|
|
|
|
Completion ($MM) |
$ |
1.358 |
$ |
1.676 |
$ |
1.672 |
$ |
1.625 |
$ |
1.693 |
$ |
1,212 |
$ |
857 |
$ |
992 |
$ per meter |
$ |
361 |
$ |
429 |
$ |
416 |
$ |
389 |
$ |
398 |
$ |
281 |
$ |
204 |
$ |
235 |
The Company also invested $57 million into
expanding its gas gathering, liquids handling and processing
capabilities in the Greater Sundance, Brazeau and the newly
established Whitehorse core areas. The most notable was the $23
million, integrated liquids storage and gathering pipeline, which
connected four of the six Greater Sundance gas plants and
eliminated the need to truck liquids from various plant sites,
resulting in greater price realizations going forward for the NGLs
produced at those plants. In addition, group pipelines in the
Brazeau, Whitehorse and Swanson areas and additional compression at
the Brazeau gas plant accounted for the remaining infrastructure
investments.
Peyto was successful in acquiring 88 sections of
new land in 2017, almost double that of 2016, with 64 sections
purchased at Crown sales and 24 purchased through acquisition from
other operators. The average cost for both types of land purchases
was $253/acre. The majority of lands were purchased in the Brazeau
area with some minor lands acquired in the Whitehorse and Sundance
areas.
The following table summarizes the capital
investments for the fourth quarter and 2017 fiscal year.
|
Three Months ended December 31 |
Twelve months ended December 31 |
($000) |
2017 |
2016 |
|
2017 |
|
2016 |
|
Land |
3,609 |
204 |
|
10,328 |
|
1,207 |
|
Seismic |
270 |
3,595 |
|
6,007 |
|
8,149 |
|
Drilling |
68,909 |
63,130 |
|
256,932 |
|
219,784 |
|
Completions |
42,124 |
37,256 |
|
133,732 |
|
105,344 |
|
Equipping
& Tie-ins |
15,695 |
14,212 |
|
53,146 |
|
41,451 |
|
Facilities
& Pipelines |
3,610 |
10,955 |
|
57,284 |
|
60,159 |
|
Acquisitions |
194 |
386 |
|
3,823 |
|
33,026 |
|
Dispositions |
- |
(228 |
) |
(42 |
) |
(255 |
) |
Leasehold
Improvements |
- |
(103 |
) |
- |
|
510 |
|
Total Capital Expenditures |
134,411 |
129,407 |
|
521,210 |
|
469,375 |
|
Reserves
Peyto was successful in growing reserves per
share in all categories in 2017, despite the year over year
reduction in commodity price forecasts used by the independent
engineering consultants. The following table illustrates the change
in reserve volumes and Net Present Value (“NPV”) of future cash
flows, discounted at 5%, before income tax and using forecast
pricing.
|
As at December 31 |
|
% Change, debt |
|
2017 |
2016 |
% Change |
adjusted per share† |
Reserves (BCFe) |
|
|
|
|
Proved Producing |
|
1,647 |
|
1,489 |
11 |
% |
(13 |
%) |
Total Proved |
|
2,708 |
|
2,426 |
12 |
% |
(12 |
%) |
Proved + Probable
Additional |
|
4,330 |
|
3,929 |
10 |
% |
(13 |
%) |
|
|
|
|
|
Net Present
Value ($millions) Discounted at 5% |
|
|
|
|
Proved Producing |
$ |
3,589 |
$ |
3,536 |
2 |
% |
(6 |
%) |
Total Proved |
$ |
5,065 |
$ |
5,032 |
1 |
% |
(4 |
%) |
Proved +
Probable Additional |
$ |
7,581 |
$ |
7,755 |
(2 |
%) |
(6 |
%) |
†Per share reserves are adjusted for changes in
net debt by converting debt to equity using the Dec 31 share price
of $15.03 for 2017 and share price of $33.21 for 2016. 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,
2017. The InSite price forecast is available at
www.InSitepc.com. For more information on Peyto’s reserves,
refer to the Press Release dated February 14, 2018 announcing the
Year End Reserve Report which is available on the website at
www.peyto.com. The complete statement of reserves data and
required reporting in compliance with NI 51-101 will be included in
Peyto's Annual Information Form to be released in March 2018.
The negative change in reserves per debt
adjusted share, was primarily due to the 55% drop in Peyto share
price which was used to convert debt to equity, while the negative
change in NPV per share was due to the 18% reduction in forecast
commodity prices that were used in the reserves evaluation partly
offset by the increase in reserve volume.
Value Reconciliation
In order to measure the success of all of the
capital invested in 2017, it is necessary to quantify the total
amount of value added during the year and compare that to the total
amount of capital invested. At Peyto’s request, the independent
engineers have run last year’s reserve evaluation with this year’s
price forecast to remove the change in value attributable to
commodity prices. 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 2017 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 2017, Peyto’s estimated net debt had
increased by 17% or $196 million to $1.327 billion while the number
of shares outstanding remained effectively the same at 165 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 $1.174 billion of Proved
Producing, $1.650 billion of Total Proven, and $2.088 billion of
Proved plus Probable Additional undiscounted reserve value, with
$521 million of capital investment, cost reductions and NGL price
enhancements. The ratio of capital expenditures to value creation
is what Peyto refers to as the NPV recycle ratio, which is simply
the undiscounted value addition, resulting from the capital
program, divided by the capital investment. For 2017, the Proved
Producing NPV recycle ratio is 2.3 which means for each dollar
invested, the Peyto team was able to create 2.3 new dollars of
Proved Producing reserve value. The historic NPV recycle ratios are
presented in the following table.
|
|
2008 |
|
2009 |
|
2010 |
|
2011 |
|
2012 |
|
2013 |
|
2014 |
|
2015 |
|
2016 |
|
2017 |
Wt. Avg. |
Capital Investment ($MM) |
$ |
139 |
$ |
73 |
$ |
261 |
$ |
379 |
$ |
618 |
$ |
578 |
$ |
690 |
$ |
594 |
$ |
469 |
$ |
521 |
NPV0 Recycle Ratio |
|
|
|
|
|
|
|
|
|
|
|
Proved
Producing |
|
2.1 |
|
5.4 |
|
3.5 |
|
2.4 |
|
1.6 |
|
1.5 |
|
1.5 |
|
2.3 |
|
2.9 |
|
2.3 |
2.2 |
Total
Proved |
|
2.5 |
|
18.9 |
|
6.1 |
|
4.7 |
|
2.2 |
|
2.0 |
|
1.7 |
|
3.3 |
|
4.2 |
|
3.2 |
3.3 |
Proved + Probable Additional |
|
2.2 |
|
27.1 |
|
10.3 |
|
6.6 |
|
3.2 |
|
4.0 |
|
2.6 |
|
5.0 |
|
7.3 |
|
4.0 |
5.1 |
*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. 2017 Proved
Producing ($1,176/$521) = 2.3).
Performance Ratios
The following table highlights annual
performance ratios both before and after the implementation of
horizontal wells in late 2009. These can be used for comparative
purposes, but it is cautioned that on their own they do not measure
investment success.
|
|
2017 |
|
|
2016 |
|
|
2015 |
|
|
2014 |
|
|
2013 |
|
|
2012 |
|
|
2011 |
|
|
2010 |
|
|
2009 |
|
Proved Producing |
|
|
|
|
|
|
|
|
|
FD&A ($/Mcfe) |
$ |
1.36 |
|
$ |
1.44 |
|
$ |
1.64 |
|
$ |
2.25 |
|
$ |
2.35 |
|
$ |
2.22 |
|
$ |
2.12 |
|
$ |
2.10 |
|
$ |
2.26 |
|
RLI (yrs) |
|
7 |
|
|
7 |
|
|
7 |
|
|
7 |
|
|
7 |
|
|
9 |
|
|
9 |
|
|
11 |
|
|
14 |
|
Recycle Ratio |
|
2.1 |
|
|
1.8 |
|
|
2.0 |
|
|
1.9 |
|
|
1.6 |
|
|
1.6 |
|
|
2.1 |
|
|
2.4 |
|
|
2.5 |
|
Reserve Replacement |
|
171 |
% |
|
153 |
% |
|
193 |
% |
|
183 |
% |
|
190 |
% |
|
284 |
% |
|
230 |
% |
|
239 |
% |
|
79 |
% |
Total Proved |
|
|
|
|
|
|
|
|
|
FD&A ($/Mcfe) |
$ |
1.39 |
|
$ |
1.01 |
|
$ |
0.72 |
|
$ |
2.37 |
|
$ |
2.23 |
|
$ |
2.04 |
|
$ |
2.13 |
|
$ |
2.35 |
|
$ |
1.73 |
|
RLI (yrs) |
|
11 |
|
|
11 |
|
|
11 |
|
|
11 |
|
|
12 |
|
|
15 |
|
|
16 |
|
|
17 |
|
|
21 |
|
Recycle Ratio |
|
2.0 |
|
|
2.6 |
|
|
4.5 |
|
|
1.8 |
|
|
1.6 |
|
|
1.7 |
|
|
2.1 |
|
|
2.1 |
|
|
3.2 |
|
Reserve Replacement |
|
225 |
% |
|
183 |
% |
|
188 |
% |
|
254 |
% |
|
230 |
% |
|
414 |
% |
|
452 |
% |
|
456 |
% |
|
422 |
% |
Future Development Capital ($ millions) |
$ |
1,488 |
|
$ |
1,305 |
|
$ |
1,381 |
|
$ |
1,721 |
|
$ |
1,406 |
|
$ |
1,318 |
|
$ |
1,111 |
|
$ |
741 |
|
$ |
446 |
|
Proved plus Probable Additional |
|
|
|
|
|
|
|
|
|
FD&A ($/Mcfe) |
$ |
1.49 |
|
$ |
0.62 |
|
$ |
0.54 |
|
$ |
2.01 |
|
$ |
1.86 |
|
$ |
1.68 |
|
$ |
1.90 |
|
$ |
2.19 |
|
$ |
1.47 |
|
RLI (yrs) |
|
18 |
|
|
18 |
|
|
17 |
|
|
18 |
|
|
19 |
|
|
22 |
|
|
22 |
|
|
25 |
|
|
29 |
|
Recycle Ratio |
|
1.9 |
|
|
4.2 |
|
|
6.1 |
|
|
2.1 |
|
|
2.0 |
|
|
2.1 |
|
|
2.4 |
|
|
2.3 |
|
|
3.8 |
|
Reserve Replacement |
|
279 |
% |
|
283 |
% |
|
287 |
% |
|
328 |
% |
|
450 |
% |
|
527 |
% |
|
585 |
% |
|
790 |
% |
|
597 |
% |
Future Development Capital
($millions) |
$ |
2,978 |
|
$ |
2,563 |
|
$ |
2,657 |
|
$ |
2,963 |
|
$ |
2,550 |
|
$ |
2,041 |
|
$ |
1,794 |
|
$ |
1,310 |
|
$ |
672 |
|
- 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 FDC, by the change in the reserves, incorporating
revisions and production, for the same period (eg. Total Proved
($521.2+$183.3)/(451.3-404.4+37.5) = $8.35/boe or $1.39/Mcfe).
- The RLI is calculated by dividing the reserves (in boes) in
each category by the annualized Q4 average production rate in
boe/year (eg. Proved Producing 274,551/(109.793x365) = 6.9).
Peyto believes that the most accurate way to evaluate the current
reserve life is by dividing the proved developed producing reserves
by the annualized 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 boe, by the FD&A costs for the period (eg. Proved Producing
(($16.79)/$8.16=2.1). 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 ((451.3-404.4+37.5)/37.5)
= 225%).
Fourth Quarter 2017
In response to the deteriorating AECO natural
gas price forecast, Peyto began reducing drilling activity in the
later part of the fourth quarter 2017. The quarter began with 9
drilling rigs active but ended with only 5 rigs drilling running,
prior to the holiday season shutdown. Completion and tie-in
activity remained robust throughout the entire fourth quarter to
catch up to any drilled but uncompleted wells. A total of $111
million was invested in the drilling of 29 gross (29 net)
horizontal wells and the completion of 45 gross (45 net) horizontal
wells. In addition, $16 million was invested in wellsite equipment
and tie-ins while $4 million was invested in new facilities and
pipelines. Seismic and land acquisitions of $4 million brought
total capital investment for the quarter to $134 million.
The majority of the drilling was concentrated in
the Brazeau Notikewin play while the remaining focused on the
Greater Sundance area Spirit River formations. Three wells were
drilled in the newly established Whitehorse area where the Company
is developing a trend of liquids rich Wilrich resource, while two
step out wells were drilled to test a new Southern Brazeau land
block. The formations and locations of the fourth quarter drilling
is illustrated in the following table.
|
Field |
Total Wells Drilled |
Zone |
Sundance |
Nosehill |
Wildhay |
Ansell/Minehead |
Whitehorse |
Kisku/Kakwa |
Brazeau |
Belly River |
|
|
|
|
|
|
|
|
Cardium |
|
|
|
|
|
|
|
|
Notikewin |
|
1 |
2 |
|
|
|
8 |
11 |
Falher |
|
|
|
|
|
|
2 |
2 |
Wilrich |
2 |
3 |
1 |
5 |
3 |
|
1 |
15 |
Bluesky |
|
1 |
|
|
|
|
|
1 |
Total |
2 |
5 |
3 |
5 |
3 |
|
11 |
29 |
Production in the fourth quarter 2017 averaged
109,793 boe/d, up 8% from 101,767 boe/d in Q4 2016, made up of 596
MMcf/d of natural gas and 10,479 bbl/d of natural gas liquids.
During October and December, periods of low AECO gas price prompted
Peyto to defer production which reduced fourth quarter average
production by 800 boe/d.
Gas plant optimization and a focus on more
liquids rich formations resulted in higher liquid yields in Q4 2017
of 17.6 bbl/MMcf, up from 16.0 bbl/MMcf in Q4 2016. Total liquids
for the quarter were split 62% pentanes plus condensates, 20%
butane, and 18% propane. Across Peyto’s nine gas plants in the Deep
Basin, propane and butane recoveries averaged only 20% and 55%,
respectively, in Q4 2017. This is out of a theoretical 80% and 97%
recovery, respectively, under deeper cutting facilities, which
would correspond to 7,800 bbls/d of additional propane and
butane.
The Company’s realized price for natural gas in
Q4 2017 was $2.15/Mcf, prior to a $0.72/Mcf hedging gain, while its
realized liquids price was $56.52/bbl, yielding a combined revenue
stream of $3.50/Mcfe. This net sales price was 4% higher than the
$3.38/Mcfe realized in Q4 2016. Total cash costs in Q4 2017 were
$0.83/Mcfe ($4.96/boe) up from $0.81/Mcfe in Q4 2016 due to
increased operating costs from higher property taxes and higher
interest rates. This total Q4 2017 cash cost included royalties of
$0.15/Mcfe, operating costs of $0.28/Mcfe, transportation of
$0.16/Mcfe, G&A of $0.03/Mcfe and interest of $0.21/Mcfe.
Peyto generated total funds from operations of $162 million
in the quarter, or $2.67/Mcfe, equating to a 76% operating margin.
DD&A charges of $1.43/Mcfe, as well as a provision for current
and future performance based compensation and income tax, reduced
FFO to earnings of $0.85/Mcfe, or a 24% profit margin. Due to
Peyto’s low costs, no impairments were recorded in the quarter.
Dividends to shareholders totaled $0.90/Mcfe.
Marketing
Alberta (AECO) daily natural gas price suffered
some of the worst volatility in its history in 2017, driven
primarily by changing operating strategies by TCPL on its NGTL
pipeline system. Daily AECO price traded as high as $4.09/GJ and as
low as minus $2.20/GJ in the year. Throughout the year, the price
deteriorated from a daily average of $2.56/GJ in the first quarter
to $1.46/GJ in the fourth quarter. Fortunately, Peyto’s hedging
practice of layering in future sales in the form of fixed price
swaps and committing the majority of its gas production to the AECO
Monthly price protected against much of this volatility. For 2017,
Peyto’s total natural gas revenues of $590.5 million, were
comprised of $523.3 million of pre-sold or hedged gas production
(89% of gas revenues) at an average price of $2.58/GJ ($2.97/mcf)
and $67.2 million of unhedged, revenue at an average price of
$2.28/GJ ($2.62/mcf), prior to NGTL fuel charges. This resulted in
a blended realized natural gas price of $2.51/GJ ($2.89/mcf).
Peyto’s realized commodity prices by component are listed in the
following table.
Commodity Prices by Component
|
Three Months ended December 31 |
Twelve months ended December 31 |
|
2017 |
2016 |
2017 |
2016 |
Natural
gas – after hedging ($/mcf) |
2.87 |
2.98 |
2.89 |
2.89 |
Natural
gas – after hedging ($/GJ) |
2.50 |
2.59 |
2.51 |
2.51 |
AECO
monthly ($/GJ) |
1.85 |
2.67 |
2.30 |
1.98 |
AECO
daily ($/GJ) |
1.55 |
2.93 |
2.03 |
2.05 |
|
|
|
|
|
Oil and natural gas
liquids ($/bbl) |
|
|
|
|
Condensate
($/bbl) |
67.54 |
56.05 |
60.20 |
47.32 |
Propane
($/bbl) |
34.95 |
14.58 |
23.16 |
8.73 |
Butane
($/bbl) |
34.94 |
28.02 |
31.27 |
21.69 |
Pentane ($/bbl) |
70.08 |
59.11 |
62.48 |
50.50 |
Total Oil
and natural gas liquids ($/bbl) |
56.52 |
45.09 |
50.02 |
40.30 |
Canadian
Light Sweet stream ($/bbl) |
69.05 |
61.58 |
62.94 |
52.99 |
Liquids prices are Peyto realized prices in Canadian dollars
adjusted for fractionation and transportationGas prices are Peyto
realized prices in Canadian dollars net of NGTL fuel charges
Peyto also realized $50.02/bbl for its blend of
natural gas liquids in the year, which represented 79% of the
Canadian Light Sweet oil price. By the fourth quarter of 2017, as a
result of the integrated liquids storage and pipeline project,
along with new marketing arrangements for its NGLs, Peyto’s
realized liquids pricing improved to 82% of the oil price. As
illustrated below, the improved realizations of greater than 80%
are expected to continue in the future.
($/bbl) |
Q1 2015 |
Q2 2015 |
Q3 2015 |
Q4 2015 |
Q1 2016 |
Q2 2016 |
Q3 2016 |
Q4 2016 |
Q1 2017 |
Q2 2017 |
Q3 2017 |
Q4 2017 |
Peyto realized blended oil and NGL price |
$ |
37.03 |
|
$ |
43.54 |
|
$ |
41.69 |
|
$ |
39.88 |
|
$ |
33.60 |
|
$ |
41.46 |
|
$ |
39.76 |
|
$ |
45.09 |
|
$ |
48.14 |
|
$ |
48.33 |
|
$ |
45.92 |
|
$ |
56.52 |
|
Canadian Light Sweet Stream |
$ |
52.72 |
|
$ |
68.50 |
|
$ |
54.70 |
|
$ |
52.02 |
|
$ |
40.83 |
|
$ |
54.70 |
|
$ |
54.82 |
|
$ |
61.58 |
|
$ |
62.19 |
|
$ |
61.95 |
|
$ |
56.65 |
|
$ |
69.02 |
|
differential |
$ |
(15.69 |
) |
$ |
(24.96 |
) |
$ |
(13.01 |
) |
$ |
(12.14 |
) |
$ |
(7.23 |
) |
$ |
(13.24 |
) |
$ |
(15.06 |
) |
$ |
(16.49 |
) |
$ |
(14.05 |
) |
$ |
(13.62 |
) |
$ |
(10.73 |
) |
$ |
(12.50 |
) |
% of |
|
70 |
% |
|
64 |
% |
|
76 |
% |
|
77 |
% |
|
82 |
% |
|
76 |
% |
|
73 |
% |
|
73 |
% |
|
77 |
% |
|
78 |
% |
|
81 |
% |
|
82 |
% |
Peyto has continued its hedging strategy to
smooth out the short term fluctuations in the price of natural gas
through future sales. This is done by selling a small portion of
the total natural gas production (inclusive of Crown Royalty
volumes) on the daily and monthly spot markets while the balance 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. Peyto’s
hedging program aims to achieve a fixed price on a descending,
graduated schedule of up to 85% of gross production for the
immediate summer or winter season and 75%, 65%, 55%, 45% and 30%
targets thereafter for the successive following seasons. These
fixed prices are achieved through a series of frequent transactions
which is similar to “dollar cost averaging” the future gas prices
in order to smooth out volatility. Peyto’s new marketing strategy
will attempt to secure the hedges at either the AECO hub or NYMEX
Henry Hub to diversify its sales between markets.
To date, Peyto has secured the following
revenues through future sales at the AECO:
|
Future Sales Volume and Revenue |
|
GJ |
$/GJ |
$ |
2018 |
177,200,000 |
$ |
2.30 |
$ |
406,982,613 |
2019 |
61,800,000 |
$ |
1.90 |
$ |
117,690,875 |
2020 |
19,630,000 |
$ |
1.79 |
$ |
35,161,850 |
Total |
258,630,000 |
$ |
2.16 |
$ |
559,835,338 |
In addition to the AECO market, Peyto has begun to secure
exposure of future volumes to the NYMEX Henry Hub with the
following volume committed for the periods shown:
|
Future Sales Volume and Revenue |
|
|
MMBTU |
$/MMBTU |
2019 |
2,140,000 |
At
Market |
2020 |
2,140,000 |
At
Market |
2021 |
2,140,000 |
At
Market |
2022 |
2,140,000 |
At
Market |
Total |
8,560,000 |
|
The AECO gas price strip currently reflects an
oversupply of gas in Alberta relative to the limited egress to
export markets. However, initiatives by NGTL towards increased
pipeline egress are being recognized by the market and a
contraction in the basis differential appears to be underway. In
addition, industry activity levels have been tempered and
production volumes in the Western Canada Sedimentary Basin are
expected to decline as the year progresses due to natural decline.
This is expected to bring the supply/demand picture more into
balance. Early progress has been made on several market
diversification initiatives to position Peyto for maximum netback
price realization. The Company has secured some Empress delivery
capacity in conjunction with the latest NGTL open season, and will
utilize this egress capacity as part of its plan to diversify
approximately 40% of production to export pricing.
Details of Peyto’s ongoing marketing efforts are
available on Peyto’s website at
http://www.peyto.com/Files/Marketing/hedges.pdf.
Activity Update
Consistent with Peyto’s revised budget, the
Company has limited drilling activity in the first quarter of 2018.
So far in 2018, Peyto has spud 8 gross (7 net) wells and rig
released 9 gross (8.6 net) wells including 2 wells which were spud
in late 2017. Peyto has completed and brought on 7 gross (7 net)
wells while 6 gross (5.4 net) are waiting on completion and
connection with on lease tie-ins.
Included in the program to date are 3 gross (1.9
net) Sundance Cardium wells that follow-up up on two wells drilled
last year which are exhibiting production performance that ranks
among the top 10 of Peyto’s 50 Sundance Cardium horizontal wells
drilled since 2009. The recent performance improvement is
attributable to continued innovation in Peyto’s completion design
which strives to constantly improve returns. While the Company is
excited about the improvements this new design brings to the
Sundance Cardium resource play, it is still proceeding cautiously,
one well at a time, until the repeatability of results of this new
design are proven. Peyto’s Cardium resource in the Greater Sundance
area contains 40-60 bbls/mmcf of natural gas liquids and is
internally estimated to contain 2.4 TCFe of gas in place with only
14% recovered to date on Peyto lands. The Company has plans for a
larger 30-40 well Cardium program in the second half of 2018
building on these recent successes.
The Company has also drilled 2 gross (1.6 net)
wells in the Whitehorse area targeting the Wilrich where innovative
changes to wellbore design has allowed drilling costs to be reduced
to $1.3MM per well. This represents a $600k/well (30%) savings over
the average of the 6 prior wells drilled in the area and underlines
Peyto’s commitment to continued cost improvement. Peyto’s
Whitehorse wells yield 30-40 bbls/mmcf of natural gas liquids which
is currently processed at a third party facility while awaiting
construction of Peyto’s own plant later in 2018.
New Ventures
Given the current natural gas price environment
in Canada, Peyto is actively pursuing opportunities to grow the
business both laterally and vertically. The Company is looking to
expand its Deep Basin core positions, as well as pursue new
opportunities outside of its traditional core properties, to
laterally expand its future drilling inventory. As well, Peyto is
pursuing opportunities to grow vertically by extracting more value
from the existing reserves and infrastructure assets. Early design
work is underway for another novel, low cost, mid-cut gas plant
process expansion that promises to significantly enhance the
recovery of propane and heavier constituents in Peyto’s gas
streams. Although still in design phase, the Company anticipates
commencement of the first of these newly designed “cheap cut”
facility expansions in 2019 and then proceeding sequentially
through four or more successive plant instalments into 2020. In all
cases, these projects will increase liquid recovery levels by an
incremental 10 to 15 bbl/MMcf for the existing plant feed
streams.
Peyto has also been in discussion to supply
meaningful volumes to intra-Alberta industrial consumers. The
Company is excited to be part of what appears to be a very bright
future for natural gas producers within Alberta as gas-fired
electrical power generation continues to take an ever-increasing
role in the province’s power needs. Furthermore, new petrochemical
projects which require natural gas feedstock are emerging that
promise to supply industrial and agricultural needs both within the
province and to export markets. Peyto’s core geographical area is
just west of Edmonton, Alberta and proximal to major highway, rail
and electrical infrastructure which provides Peyto with an inherent
advantage in serving many of these growth industries.
2018 Outlook
Peyto has now entered its 20th year of
operations in the Western Canadian Sedimentary Basin. Over that
time, the Company has grown from a tiny junior to the fifth largest
natural gas producer in Canada. That growth has come almost
exclusively through the drill bit and has generated some of the
highest returns on capital in the industry. Throughout that time,
Peyto has remained nimble and dynamic, adjusting its business plans
to account for the changing market conditions so as to ensure
capital was continuing to deliver the highest returns possible.
That’s why Peyto’s strategy is called a “returns focused strategy”
because it is the maximization of return on capital invested that
defines the business. Going forward that will not change. The
Company will continue to look for ways to invest capital in the
energy business that yields the highest possible returns. At times
those investments might be to develop new reserves, at other times,
to extract additional value from existing reserves. Delivering
maximum return to shareholders on whatever capital is invested will
continue to remain front and center.
Conference Call and Webcast
A conference call will be held with the senior
management of Peyto to answer questions with respect to the 2017
fourth quarter and full year financial results on Thursday, March
1st, 2018, at 9:00 a.m. Mountain Standard Time (MST), or 11:00 a.m.
Eastern Standard Time (EST). To participate, please call
1-844-492-6041 (North America) or 1-478-219-0837 (International).
Shareholders and interested investors are encouraged to ask
questions about Peyto and its most recent results. Questions can be
submitted to info@peyto.com. The conference call can also be
accessed through the internet at
https://edge.media-server.com/m6/p/6w4b8k4a. 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/Files/Financials/2017/2017MDandA.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 Thursday, May 10, 2018 at the Eau
Claire Tower, +15 level, 600 – 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 GeePresident and CEOFebruary 28, 2018
Certain information set forth in this
document and Management’s Discussion and Analysis, including
management's assessment of Peyto’s future plans and operations,
capital expenditures and capital efficiencies, contains
forward-looking statements. By their nature, forward-looking
statements are subject to numerous risks and uncertainties, some of
which are beyond these parties' control, including the impact of
general economic conditions, industry conditions, volatility of
commodity prices, currency fluctuations, imprecision of reserve
estimates, environmental risks, competition from other industry
participants, the lack of availability of qualified personnel or
management, stock market volatility and ability to access
sufficient capital from internal and external sources.
Readers are cautioned that the assumptions used in the preparation
of such information, although considered reasonable at the time of
preparation, may prove to be imprecise and, as such, undue reliance
should not be placed on forward-looking statements. Peyto's actual
results, performance or achievement could differ materially from
those expressed in, or implied by, these forward-looking statements
and, accordingly, no assurance can be given that any of the events
anticipated by the forward-looking statements will transpire or
occur, or if any of them do so, what benefits Peyto will derive
there from. In addition, Peyto is providing future oriented
financial information set out in this press release for the
purposes of providing clarity with respect to Peyto’s strategic
direction and readers are cautioned that this information may not
be appropriate for any other purpose. Other than is required
pursuant to applicable securities law, Peyto does not undertake to
update forward looking statements at any particular time. To
provide a single unit of production for analytical purposes,
natural gas production and reserves volumes are converted
mathematically to equivalent barrels of oil (BOE). Peyto uses the
industry-accepted standard conversion of six thousand cubic feet of
natural gas to one barrel of oil (6 Mcf = 1 bbl). The 6:1 BOE
ratio is based on an energy equivalency conversion method primarily
applicable at the burner tip. It does not represent a value
equivalency at the wellhead and is not based on current
prices. While the BOE ratio is useful for comparative measures
and observing trends, it does not accurately reflect individual
product values and might be misleading, particularly if used in
isolation. As well, given that the value ratio, based on the
current price of crude oil to natural gas, is significantly
different from the 6:1 energy equivalency ratio, using a 6:1
conversion ratio may be misleading as an indication of
value.
Peyto Exploration & Development
Corp.Balance Sheet (Amounts in $
thousands)
|
December
312017 |
December 312016 |
Assets |
|
|
Current assets |
|
|
Cash |
5,652 |
|
2,102 |
|
Accounts
receivable |
90,242 |
|
94,813 |
|
Due from
private placement (Note 6) |
- |
|
4,930 |
|
Derivative financial instruments (Note 11) |
135,017 |
|
- |
|
Prepaid expenses |
12,578 |
|
13,385 |
|
|
243,489 |
|
115,230 |
|
|
|
|
Long-term
derivative financial instruments (Note 11) |
16,233 |
|
- |
|
Property, plant and equipment, net (Note 3) |
3,584,992 |
|
3,347,859 |
|
|
3,601,225 |
|
3,347,859 |
|
|
3,844,714 |
|
3,463,089 |
|
|
|
|
Liabilities |
|
|
Current liabilities |
|
|
Accounts
payable and accrued liabilities |
132,776 |
|
158,173 |
|
Dividends
payable (Note 6) |
18,136 |
|
18,109 |
|
Provision
for future performance based compensation (Note 9) |
9,166 |
|
6,854 |
|
Derivative financial instruments (Note 11) |
- |
|
119,280 |
|
|
160,078 |
|
302,416 |
|
|
|
|
Long-term
debt (Note 4) |
1,285,000 |
|
1,070,000 |
|
Long-term
derivative financial instruments (Note 11) |
- |
|
31,465 |
|
Provision
for future performance based compensation (Note 9) |
- |
|
4,499 |
|
Decommissioning provision (Note 5) |
143,805 |
|
127,763 |
|
Deferred income taxes (Note 10) |
532,853 |
|
386,012 |
|
|
1,961,658 |
|
1,619,739 |
|
|
|
|
Equity |
|
|
Shareholders’ capital (Note 6) |
1,649,537 |
|
1,641,982 |
|
Shares to
be issued (Note 6) |
- |
|
4,930 |
|
Retained
earnings (deficit) |
(40,261 |
) |
776 |
|
Accumulated other comprehensive income (loss) (Note 6) |
113,702 |
|
(106,754 |
) |
|
1,722,978 |
|
1,540,934 |
|
|
3,844,714 |
|
3,463,089 |
|
|
|
|
Approved
by the Board of Directors |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(signed)
“Michael MacBean” |
|
|
|
|
|
|
|
|
(signed)
“Darren Gee” |
Director |
|
|
|
|
|
|
|
|
Director |
|
|
|
|
|
|
|
|
|
|
Peyto Exploration & Development
Corp.Income Statement (Amounts in $
thousands)
|
|
Year ended December 31 |
|
|
|
|
2017 |
|
|
2016 |
|
Revenue |
|
|
|
|
Oil and gas sales |
|
|
|
703,013 |
|
|
559,915 |
|
Realized gain on hedges
(Note 11) |
|
|
|
57,943 |
|
|
118,473 |
|
Royalties |
|
|
|
(34,104 |
) |
|
(28,330 |
) |
Petroleum
and natural gas sales, net |
|
|
|
726,852 |
|
|
650,058 |
|
Expenses |
|
|
|
|
Operating (Note 7) |
|
|
|
60,423 |
|
|
53,231 |
|
Transportation |
|
|
|
37,640 |
|
|
34,550 |
|
General and
administrative |
|
|
|
8,538 |
|
|
8,304 |
|
Market and reserves
based bonus (Note 9) |
|
|
|
15,684 |
|
|
25,770 |
|
Provision for future
performance based compensation |
|
|
|
(2,187 |
) |
|
9,354 |
|
Interest (Note 8) |
|
|
|
46,530 |
|
|
39,380 |
|
Accretion of
decommissioning provision (Note 5) |
|
|
|
3,105 |
|
|
2,456 |
|
Depletion and
depreciation (Note 3) |
|
|
|
315,314 |
|
|
330,745 |
|
Net gain on disposition
of assets (Note 3) |
|
|
|
(79 |
) |
|
(7,885 |
) |
|
|
|
|
484,968 |
|
|
495,905 |
|
Earnings before taxes |
|
|
|
241,884 |
|
|
154,153 |
|
|
|
|
|
|
Income
tax |
|
|
|
|
Deferred income tax
expense (Note 10) |
|
|
|
65,309 |
|
|
41,805 |
|
Earnings for the year |
|
|
|
176,575 |
|
|
112,348 |
|
|
|
|
|
|
|
|
|
|
|
Earnings per
share (Note 6) |
|
|
|
|
Basic and diluted |
|
|
$ |
1.07 |
|
$ |
0.69 |
|
|
|
|
|
|
Weighted
average number of common shares outstanding (Note 6) |
|
|
|
|
Basic and diluted |
|
|
|
164,856,042 |
|
|
162,573,515 |
|
|
|
|
|
|
Peyto Exploration & Development
Corp.Statement of Comprehensive (Loss)
Income (Amounts in $ thousands)
|
|
Year ended December 31 |
|
|
|
2017 |
|
2016 |
|
Earnings for
the year |
|
|
176,575 |
|
112,348 |
|
Other
comprehensive income |
|
|
|
|
Change in unrealized
gain (loss) on cash flow hedges |
|
|
359,938 |
|
(95,142 |
) |
Deferred tax (expense)
recovery |
|
|
(81,539 |
) |
57,676 |
|
Realized
(gain) on cash flow hedges |
|
|
(57,943 |
) |
(118,473 |
) |
Comprehensive Income (Loss) Income |
|
|
397,031 |
|
(43,591 |
) |
|
|
|
|
|
Peyto Exploration & Development
Corp.Statement of Changes in
Equity (Amounts in $ thousands)
|
Year ended December 31 |
|
2017 |
|
2016 |
|
Shareholders’ capital, Beginning of Year |
1,641,982 |
|
1,467,264 |
|
Equity offering |
7,574 |
|
172,500 |
|
Common shares issued by
private placement (Note 6) |
- |
|
7,644 |
|
Common shares issuance
costs (net of tax) |
(19 |
) |
(5,426 |
) |
Shareholders’ capital, End of Year |
1,649,537 |
|
1,641,982 |
|
|
|
|
|
|
|
|
|
|
Common shares to be issued, Beginning of Year |
4,930 |
|
3,769 |
|
Common shares issued
(Note 6) |
(4,930 |
) |
(3,769 |
) |
Common
shares to be issued (Note 6) |
- |
|
4,930 |
|
Common shares to be issued, End of Year |
- |
|
4,930 |
|
|
|
|
|
|
|
|
|
|
Retained earnings, Beginning of Year |
776 |
|
103,339 |
|
Earnings for the
year |
176,575 |
|
112,348 |
|
Dividends
(Note 6) |
(217,612 |
) |
(214,911 |
) |
Retained earnings (deficit), End of Year |
(40,261 |
) |
776 |
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive (loss) income, Beginning of
Year |
(106,754 |
) |
49,185 |
|
Other
comprehensive income (loss) |
220,456 |
|
(155,939 |
) |
Accumulated other comprehensive income (loss), End of
Year |
113,702 |
|
(106,754 |
) |
|
|
|
|
|
|
|
|
|
Total Equity |
1,722,978 |
|
1,540,934 |
|
|
|
|
Peyto Exploration & Development
Corp.Statement of Cash
Flows (Amounts in $ thousands)
|
|
Year ended December 31 |
|
|
|
2017 |
|
2016 |
|
Cash provided
by (used in) |
|
|
|
|
Operating
activities |
|
|
|
|
Earnings |
|
|
176,575 |
|
112,348 |
|
Items not requiring
cash: |
|
|
|
|
Deferred income
tax |
|
|
65,309 |
|
41,805 |
|
Depletion and
depreciation |
|
|
315,314 |
|
330,745 |
|
Accretion of
decommissioning provision |
|
|
3,105 |
|
2,456 |
|
Net gain on
disposition of assets |
|
|
(79 |
) |
(7,885 |
) |
Long term
portion of future performance based compensation |
|
|
(4,499 |
) |
4,499 |
|
Change in
non-cash working capital related to operating activities |
|
|
(20,381 |
) |
24,661 |
|
|
|
|
535,344 |
|
508,629 |
|
Financing
activities |
|
|
|
|
Issuance of common
shares |
|
|
7,574 |
|
180,144 |
|
Issuance costs |
|
|
(26 |
) |
(7,432 |
) |
Cash dividends
paid |
|
|
(217,586 |
) |
(214,287 |
) |
Increase (decrease) in
bank debt |
|
|
215,000 |
|
(75,000 |
) |
Issuance of long term
notes |
|
|
- |
|
100,000 |
|
|
|
|
4,962 |
|
(16,575 |
) |
Investing
activities |
|
|
|
|
Additions to property,
plant and equipmentChange in prepaid capitalChange in non-cash
working capital relating to investing activities |
|
|
(521,210)(18,220)2,674 |
|
(469,375)(4,525)(16,052) |
|
|
|
|
(536,756 |
) |
(489,952 |
) |
|
|
|
|
|
Net increase in cash |
|
|
3,550 |
|
2,102 |
|
Cash, beginning of year |
|
|
2,102 |
|
- |
|
Cash, end of year |
|
|
5,652 |
|
2,102 |
|
The following amounts are included in Cash flows from operating
activities: |
|
|
|
|
|
|
|
|
|
Cash interest paid |
|
|
49,020 |
|
34,714 |
|
Cash
taxes paid |
|
|
- |
|
- |
|
|
|
|
|
|
Peyto Exploration & Development
Corp.Notes to Financial
StatementsAs at December 31, 2017 and
2016(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 300, 600 – 3rd Avenue SW,
Calgary, Alberta, Canada, T2P 0G5.
These financial statements were approved and
authorized for issuance by the Board of Directors of Peyto on
February 27, 2018.
2. Basis
of presentation
These financial statements (“financial
statements”) as at and for the years ended December 31, 2017 and
December 31, 2016 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
judgementsThe 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,
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 cash generating units
(“CGU”) 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. CGU 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) Standards issued but not yet effective
In July 2014, the IASB completed the final
elements of IFRS 9 "Financial Instruments." The Standard supersedes
earlier versions of IFRS 9 and completes the IASB’s project to
replace IAS 39 "Financial Instruments: Recognition and
Measurement." IFRS 9, as amended, includes a principle-based
approach for classification and measurement of financial assets, a
single 'expected loss’ impairment model and a
substantially-reformed approach to hedge accounting. The Standard
will come into effect for annual periods beginning on or after
January 1, 2018, with earlier adoption permitted. IFRS 9 will be
applied by Peyto on January 1, 2018. The impact of the
standard has been evaluated and is expected to not have a material
impact on the Company’s financial statements.
In May 2014, the IASB issued IFRS 15 "Revenue
from Contracts with Customers," which replaces IAS 18 "Revenue,"
IAS 11 "Construction Contracts," and related interpretations. The
standard is required to be adopted for fiscal years beginning on or
after January 1, 2018, with earlier adoption permitted. IFRS 15
will be applied by Peyto on January 1, 2018. IFRS 15 provides
clarification for recognizing revenue from contracts with customers
and establishes a single revenue recognition and measurement
framework. The impact of the standard has been evaluated and is
expected to have no material impact on the Company’s financial
statements. Additional disclosure may be required upon
implementation of IFRS 15 in order to provide sufficient
information to enable users to understand the nature, amount,
timing, and uncertainty of revenue and cash flows arising from the
contracts with customers.
In January 2016, the IASB issued IFRS 16
“Leases”, which replaces IAS 17 “Leases”. For lessees applying IFRS
16, a single recognition and measurement model for leases would
apply, with required recognition of assets and liabilities for most
leases. The standard will come into effect for annual periods
beginning on or after January 1, 2019, with earlier adoption
permitted. The Company is currently evaluating the impact of the
standard on the Company’s financial statements.
d) Presentation currencyAll amounts in these
financial statements are expressed in Canadian dollars, as this is
the functional and presentation currency of the Company.
e) Cash EquivalentsCash equivalents include
term deposits or a similar type of instrument, with a maturity of
three months or less when purchased.
f) Jointly controlled operations and
assetsCertain activities of the Company are conducted
jointly with others where the participants have a direct ownership
interest in, and jointly control, the related assets. Accordingly,
the accounts of Peyto reflect only its working interest share of
revenues, expenses and capital expenditures related to these
jointly controlled assets.
Processing and gathering recoveries related to
joint operations reduces operating expenses.
g) Exploration and evaluation
assetsPre-license costsCosts 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
costsOnce 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.
h) Property, plant and equipmentOil 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
swapsFor 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 depreciationOil
and natural gas properties are depleted on a unit-of-production
basis over 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 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.
i) Corporate assetsCorporate 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.
j) Impairment of non-financial assetsThe
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 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 CGU’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.
k) LeasesLeases 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.
l) Financial instrumentsFinancial 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
managementDerivative 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 derivativesAn 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
exemptionContracts 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.
m) HedgingThe 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 hedging 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.
n) InventoriesInventories 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.
o) Provisions
GeneralProvisions 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
provisionDecommissioning 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.
p) Taxes
Current income taxCurrent
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 taxThe 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.
q) Revenue recognitionRevenue 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
dispositionFor 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.
r) Borrowing costsBorrowing 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.
s) Share-based paymentsCash-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.
t) Earnings per shareBasic 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.
u) Share capitalCommon shares are classified
within equity. Incremental costs directly attributable to the
issuance of shares are recognized as a deduction from Share
capital.
3. Property,
plant and equipment, net
|
|
|
Cost |
|
|
At December 31, 2015 |
|
4,416,643 |
|
Additions |
|
473,930 |
|
Decommissioning
provision net additions |
|
6,425 |
|
Prepaid
capital |
|
4,525 |
|
At December 31, 2016 |
|
4,901,523 |
|
Additions |
|
520,394 |
|
Decommissioning
provision net additions |
|
12,935 |
|
Prepaid capital |
|
18,220 |
|
At December 31, 2017 |
|
5,453,072 |
|
|
|
|
Accumulated depletion and depreciation |
|
|
At December 31, 2015 |
|
(1,226,584 |
) |
Depletion
and depreciation |
|
(327,080 |
) |
At December 31, 2016 |
|
(1,553,664 |
) |
Depletion and
depreciation |
|
(314,416 |
) |
At December 31, 2017 |
|
(1,868,080 |
) |
|
|
|
Carrying
amount at December 31, 2016 |
|
3,347,859 |
|
Carrying amount at December 31, 2017 |
|
3,584,992 |
|
The Company closed various asset swap
arrangements during the year ended December 31, 2017. For purposes
of determining a gain on disposition, the estimated fair value was
based on the fair value of the assets received. The Company
recorded a gain of $1.6 million for the year ended December 31,
2017 (2016- $12.7 million gain). The gain is offset by a loss
relating to 2017 land expiries in the amount of $1.5 million (2016-
$4.8 million loss).
During, 2017 Peyto capitalized $7.9 million
(2016 - $7.1 million) of general and administrative expense
directly attributable to exploration and development
activities.
At December 31, 2017, an impairment test was
performed at the CGU level due to the decline in commodity prices.
The Company determined that oil and natural gas properties were not
impaired at December 31, 2017 and 2016. The recoverable amount
(fair value of the assets less cost of disposal) was determined
using a discounted cash flow approach based on Proved Plus Probable
Reserves at December 31, 2017, current commodity prices and a risk
adjusted before tax discount rate of 12%.
The benchmark prices used in the Company’s
forecast at December 31, 2017 are outlined as follows:
|
2018 |
2019 |
2020 |
2021 |
2022 |
2023 |
2024 |
AECO
natural gas ($/MMBtu) |
2.52 |
2.93 |
3.22 |
3.51 |
3.75 |
3.85 |
3.95 |
Prices subsequent to 2024 have been adjusted for
estimated annual inflation of 2%
All else being equal, a 1% increase in the
assumed discount rate or a 10% decrease in future planned cash
flows would not result in an impairment for the years ended
December 31, 2017 and 2016.
4. Long-term
debt
|
December 31, 2017 |
December 31, 2016 |
Bank credit facility |
765,000 |
550,000 |
Senior
unsecured notes |
520,000 |
520,000 |
Balance, end of the year |
1,285,000 |
1,070,000 |
The Company has a syndicated $1.3 billion
extendible unsecured revolving credit facility with a stated term
date of October 13, 2021. The bank facility is made up of a $40
million working capital sub-tranche and a $1.26 billion production
line. The facilities are available on a revolving
basis. Borrowings under the facility bear interest at
Canadian bank prime 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 50 basis points and 215 basis points on Canadian bank
prime and US base rate borrowings and between 150 basis points and
315 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 30 to 63 basis points.
On April 26, 2016, the amended and restated note
purchase and private shelf agreement dated January 3, 2012 and
restated as of April 26, 2013 was amended to increase the shelf
facility from $150 million to $250 million.
On October 24, 2016 Peyto closed an issuance of
CDN $100 million of senior unsecured notes. The notes were issued
by way of private placement pursuant to the amended and restated
note purchase and private shelf agreement and rank equally with
Peyto’s obligations under its bank facility and existing note
purchase agreements. The notes have a coupon rate of 3.7% and
mature on October 24, 2023. Interest will be paid semi-annually in
arrears.
Peyto is in compliance with all financial
covenants at December 31, 2017.
Outstanding senior notes are as follows:
Senior Unsecured Notes |
Date Issued |
Rate |
Maturity Date |
$100
million |
January 3, 2012 |
4.39 |
% |
January 3, 2019 |
$50
million |
September 6, 2012 |
4.88 |
% |
September 6, 2022 |
$120
million |
December 4, 2013 |
4.50 |
% |
December 4, 2020 |
$50
million |
July
3, 2014 |
3.79 |
% |
July
3, 2022 |
$100
million |
May 1,
2015 |
4.26 |
% |
May 1,
2025 |
$100 million |
October 24, 2016 |
3.70 |
% |
October 24, 2023 |
Peyto’s total borrowing capacity is $1.82
billion and Peyto’s credit facility is $1.3 billion.
The fair value of all senior notes as at
December 31, 2017, is $529.0 million compared to a carrying value
of $520.0 million.
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.
Total interest expense for 2017 was $46.5 million (2016 - $39.3
million) and the average borrowing rate for 2017 was 3.9% (2016 –
3.7%).
5. Decommissioning
provision
The Company makes provision for the future cost
of decommissioning wells and facilities on a discounted basis based
on the timing of abandonment and reclamation 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, 2015 |
118,882 |
|
New or increased
provisions |
16,285 |
|
Accretion of
discount |
2,456 |
|
Change in
discount rate and estimates |
(9,860 |
) |
Balance,
December 31, 2016 |
127,763 |
|
New or increased provisions |
14,087 |
|
Accretion of
discount |
3,105 |
|
Change in
discount rate and estimates |
(1,151 |
) |
Balance,
December 31, 2017 |
143,805 |
|
Current |
- |
|
Non-current |
143,805 |
|
|
|
The Company has estimated the net present value
of its total decommissioning provision to be $143.8 million as at
December 31, 2017 (2016 – $127.8 million) based on a total future
undiscounted liability of $289.7 million (2016 – $258.2 million).
At December 31, 2017 management estimates that these payments are
expected to be made over the next 49 years (2016 – 48 years) with
the majority of payments being made in years 2046 to 2067. The Bank
of Canada’s long term bond rate of 2.26 per cent (2016 – 2.31 per
cent) and an inflation rate of 2.0 per cent (2016 – 2.0 per cent)
were used to calculate the present value of the decommissioning
provision.
6. Equity
Share
capitalAuthorized: Unlimited number
of voting common shares
Issued and Outstanding
Common Shares (no par value) |
Number of Common Shares |
Amount$ |
Balance, December 31, 2015 |
158,958,273 |
1,467,264 |
|
Common
shares issued by private placement |
281,270 |
7,644 |
|
Equity
offering |
5,390,625 |
172,500 |
|
Common
share issuance costs (net of tax) |
- |
(5,426 |
) |
Balance, December 31, 2016 |
164,630,168 |
1,641,982 |
|
Common
shares issued by private placement |
244,007 |
7,574 |
|
Common
share issuance costs (net of tax) |
- |
(19 |
) |
Balance, December 31, 2017 |
164,874,175 |
1,649,537 |
|
On March 15, 2016, Peyto completed a private
placement of 132,240 common shares to employees and consultants for
net proceeds of $3.9 million ($29.30 per common share).
On May 18, 2016, Peyto completed a public
offering for 5,390,625 common shares at a price of $32.00 per
common share, for net proceeds of $165.6 million.
On December 31, 2016, Peyto completed a private
placement of 146,755 common shares to employees and consultants for
net proceeds of $4.9 million ($33.59 per share). These common
shares were issued January 6, 2017.
On March 14, 2017, Peyto completed a private
placement of 97,252 common shares to employees and consultants for
net proceeds of $2.6 million ($27.19 per common share).
Per share amountsEarnings per
share or unit have been calculated based upon the weighted average
number of common shares outstanding for the year ended December 31,
2017 of 164,856,042 (2016 – 162,573,515). There are no
dilutive instruments outstanding.
DividendsDuring the year ended
December 31, 2017, Peyto declared and paid dividends of $1.32 per
common share or $0.11 per common share for the months of January to
December 2017 totaling $217.6 million (2016 - $1.32 or $0.11
per common share for the months of January to December totaling
$214.9 million).
On January 15, 2018, Peyto declared dividends of
$0.06 per common share that were paid on February 15, 2018.
On February 15, 2018, Peyto declared dividends of $0.06 per common
share to be paid to shareholders of record on February 28,
2018. These dividends will be paid on March 15, 2018.
Accumulated other comprehensive
incomeComprehensive 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 gainsGains
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 11.
7. Operating
expenses
The Company’s operating expenses include all
costs with respect to day-to-day well and facility
operations. Processing and gathering recoveries related to
jointly owned production reduces gross field expenses to Peyto’s
operating expenses.
|
|
Years ended December 31 |
|
|
|
2017 |
|
2016 |
|
Gross field
expenses |
|
|
72,238 |
|
65,984 |
|
Cost
recoveries related to processing and gathering of partner
production |
|
|
(11,815 |
) |
(12,753 |
) |
Total operating expenses |
|
|
60,423 |
|
53,231 |
|
8. Finance
costs
|
|
Years ended December 31 |
|
|
|
2017 |
2016 |
Interest expense |
|
|
46,530 |
39,380 |
Accretion
of decommissioning provisions |
|
|
3,105 |
2,456 |
Total finance costs |
|
|
49,635 |
41,836 |
9. 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 componentThe
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 componentUnder 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 total amount expensed under these plans was as
follows:
|
|
|
Years ended December 31 |
|
|
|
2017 |
2016 |
Market based
compensation |
|
|
13,867 |
17,020 |
Reserve based
compensation |
|
|
1,817 |
8,750 |
Total market and reserves based compensation |
|
|
15,684 |
25,770 |
The fair values were calculated using a
Black-Scholes valuation model. The principal inputs to the
option valuation model were:
|
December 312017 |
December 312016 |
Share price |
$ |
33.80 |
|
$ |
33.80 |
|
Exercise price (net of
dividend) |
$ |
22.77 |
|
$ |
22.77 |
|
Expected
volatility |
|
0 |
% |
|
0 |
% |
Option life |
|
1
year |
|
|
1 - 2
years |
|
Forfeiture rate |
|
3 |
% |
|
5 |
% |
Risk-free
interest rate |
|
0 |
% |
|
0 |
% |
The changes in total rights outstanding and
related weighted average exercise prices for the years ended
December 31, 2017 and 2016 were as follows:
|
Rights (number of shares) |
Weighted Average Grant Price ($) |
Balance, December 31, 2015 |
1,004,717 |
|
$ |
34.23 |
Granted |
3,798,500 |
|
$ |
24.09 |
Cancelled |
(14,000 |
) |
$ |
24.67 |
Paid
out |
(2,265,550 |
) |
$ |
27.78 |
Balance, December 31, 2016 |
2,523,667 |
|
$ |
24.09 |
Granted |
3,918,500 |
|
$ |
33.64 |
Cancelled |
(17,867 |
) |
$ |
29.98 |
Paid
out |
(5,166,900 |
) |
$ |
31.32 |
Balance, December 31, 2017 |
1,257,400 |
|
$ |
24.09 |
Subsequent to December 31, 2017, 3.9 million
rights were granted at a price of $14.68 to be valued at the ten
day weighted average market price at December 31, 2017 and vesting
1/3 on each of December 31, 2018, December 31, 2019 and December
31, 2020.
10. Income
taxes
|
2017 |
|
2016 |
|
Earnings before income taxes |
241,884 |
|
154,153 |
|
Statutory
income tax rate |
27.00 |
% |
27.00 |
% |
Expected income
taxes |
65,309 |
|
41,622 |
|
Increase (decrease) in
income taxes from: |
|
|
True-up tax
pools |
- |
|
- |
|
Rate change |
- |
|
- |
|
Other |
- |
|
183 |
|
Total income tax expense |
65,309 |
|
41,805 |
|
|
|
|
Deferred income tax
expense |
65,309 |
|
41,805 |
|
Current
income tax expense |
- |
|
- |
|
Total income tax expense |
65,309 |
|
41,805 |
|
Differences between tax
base and reported amounts for depreciable assets |
(535,809 |
) |
(474,918 |
) |
Derivative financial
instruments |
(40,838 |
) |
40,701 |
|
Share issuance
costs |
2,388 |
|
3,545 |
|
Future performance
based bonuses |
2,475 |
|
2,728 |
|
Provision for
decommission provision |
38,827 |
|
34,496 |
|
Cumulative eligible
capital |
- |
|
5,331 |
|
Charitable
donations |
- |
|
62 |
|
Tax loss
carry-forwards recognized |
104 |
|
2,043 |
|
Deferred income taxes |
(532,853 |
) |
(386,012 |
) |
At December 31, 2017 the Company has tax pools
of approximately $1,550.4 million (2016 - $1,579.9 million)
available for deduction against future income.
11. Financial
instruments
Financial instrument classification and
measurementFinancial 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, 2017.
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
liabilitiesThe 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,
2017 and 2016, 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 excluding
senior notes (Note 4) approximates its fair value due to the
floating rate of interest charged under the credit facility.
Market riskMarket 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, 2017:
Natural GasPeriod
Hedged – Monthly Index |
Type |
Daily Volume |
Price(CAD) |
January 1, 2016 to March 31, 2018 |
Fixed
Price |
5,000
GJ |
$2.54/GJ |
April
1, 2016 to March 31, 2018 |
Fixed
Price |
60,000
GJ |
$2.42/GJ to $2.75/GJ |
April
1, 2016 to October 31, 2018 |
Fixed
Price |
35,000
GJ |
$2.10/GJ to $2.60/GJ |
May
1, 2016 to October 31, 2018 |
Fixed
Price |
20,000
GJ |
$2.20/GJ to $2.35/GJ |
July
1, 2016 to October 31, 2018 |
Fixed
Price |
20,000
GJ |
$2.28/GJ to $2.45/GJ |
August 1, 2016 to October 31, 2018 |
Fixed
Price |
25,000
GJ |
$2.3175/GJ to $2.5525/GJ |
November 1, 2016 to March 31, 2018 |
Fixed
Price |
5,000
GJ |
$2.51/GJ |
April
1, 2017 to March 31, 2018 |
Fixed
Price |
110,000 GJ |
$2.6050/GJ to $3.1075/GJ |
April
1, 2017 to October 31, 2018 |
Fixed
Price |
10,000
GJ |
$2.585/GJ to $2.745/GJ |
October 1, 2017 to March 31, 2018 |
Fixed
Price |
25,000
GJ |
$2.365/GJ- $2.455/GJ |
November 1, 2017 to March 31, 2018 |
Fixed
Price |
185,000 GJ |
$2.285/GJ to $3.27/GJ |
November 1, 2017 to October 31, 2018 |
Fixed
Price |
5,000
GJ |
$2.92/GJ |
December 1, 2017 to March 31, 2018 |
Fixed
Price |
45,000
GJ |
$1.95/GJ to $2.465/GJ |
January 1, 2018 to December 31, 2020 |
Fixed
Price |
20,000
GJ |
$2.00/GJ to $2.040/GJ |
April
1, 2018 to October 31, 2018 |
Fixed
Price |
90,000
GJ |
$1.59/GJ to $2.565/GJ |
April
1, 2018 to March 31, 2019 |
Fixed
Price |
180,000 GJ |
$1.54/GJ to $2.625/GJ |
April
1, 2018 to October 31, 2019 |
Fixed
Price |
5,000
GJ |
$1.90/GJ |
April
1, 2019 to March 31, 2020 |
Fixed
Price |
45,000
GJ |
$1.60/GJ to $2.50/GJ |
November 1, 2019 to March 31, 2020 |
Fixed Price |
15,000 GJ |
$2.02/GJ to $2.05/GJ |
Natural GasPeriod
Hedged – Daily Index |
Type |
Daily Volume |
Price(CAD) |
April
1, 2018 to October 31, 2018 |
Fixed
Price |
15,000
GJ |
$1.54/GJ to $1.63/GJ |
April 1, 2018 to October 31, 2019 |
Fixed Price |
30,000 GJ |
$1.50/GJ to $1.67/GJ |
As at December 31, 2017, Peyto had committed to
the future sale of 217,245,000 gigajoules (GJ) of natural gas at an
average price of $2.29 per GJ or $2.63 per mcf. Had these
contracts been closed on December 31, 2017, Peyto would have
realized a gain in the amount of $151.3 million. If the AECO gas
price on December 31, 2017 were to increase by $0.10/GJ, the
unrealized loss would decrease by approximately $21.7
million. An opposite change in commodity prices rates would
result in an opposite impact on other comprehensive
income.
Subsequent to December 31, 2017 Peyto entered
into the following contracts:
Natural GasPeriod
Hedged – Monthly Index |
Type |
Daily Volume |
Price(CAD) |
April
1, 2018 to October 31, 2018 |
Fixed
Price |
15,000
GJ |
$1.30/GJ |
April
1, 2018 to March 31, 2020 |
Fixed
Price |
10,000
GJ |
$1.43/GJ to $1.44/GJ |
November 1, 2018 to March 31, 2019 |
Fixed
Price |
60,000
GJ |
$1.75/GJ to $1.9525/GJ |
November 1, 2018 to March 31, 2020 |
Fixed
Price |
5,000
GJ |
$1.5725/GJ |
April
1, 2019 to October 31, 2019 |
Fixed
Price |
15,000
GJ |
$1.30/GJ |
April
1, 2019 to March 31, 2020 |
Fixed
Price |
25,000
GJ |
$1.45/GJ to $1.51/GJ |
April
1, 2020 to October 31, 2020 |
Fixed
Price |
15,000
GJ |
$1.30/GJ |
Natural GasPeriod
Hedged – Daily Index |
Type |
Daily Volume |
Price(CAD) |
April 1, 2018 to March 31, 2019 |
Fixed Price |
10,000 GJ |
$1.40/GJ to $1.53/GJ |
Interest rate riskThe 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, 2017 would decrease by
$6.5 million. An opposite change in interest rates would
result in an opposite impact on earnings before income
tax.
Credit riskA 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, 2017, approximately 41% was received from three
companies (15%,14% and 12%) (December 31, 2016 – 72% was received
from five companies (18%, 17%, 14%, 12%, and 11%). Of the
Company’s accounts receivable at December 31, 2017, approximately
25% was receivable from two companies (11% and 14%) (December 31,
2016 approximately 70% was receivable from five companies (18%,
15%, 14%, 12% and 11%). 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’s accounts receivable was aged as follows at
December 31, 2017:
|
|
|
December 31, 2017 |
Current (less than 30
days) |
|
|
87,957 |
31-60 days |
|
|
1,859 |
61-90 days |
|
|
78 |
Past due (more than 90
days) |
|
|
348 |
Balance, December 31, 2017 |
|
|
90,242 |
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, 2017,
there was no impairment of any of the financial assets of the
Company.
Liquidity riskLiquidity 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, 2017:
|
< 1 Year |
1-2 Years |
3-5 Years |
Thereafter |
Accounts payable and
accrued liabilities |
132,776 |
- |
- |
- |
Dividends payable |
18,136 |
- |
- |
- |
Provision for future
market and reserves based bonus |
9,166 |
- |
- |
- |
Long-term debt(1) |
- |
- |
765,000 |
- |
Unsecured
senior notes |
- |
100,000 |
220,000 |
200,000 |
(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 312017 |
December 312016 |
Equity |
1,722,978 |
|
1,540,934 |
Long-term debt |
1,285,000 |
|
1,070,000 |
Working
capital deficit (surplus) |
(83,411 |
) |
187,186 |
|
2,924,567 |
|
2,798,120 |
12. Related
party transactions
Certain directors of Peyto are considered to
have significant influence over other reporting entities that Peyto
engages in transactions with. Such services are provided in
the normal course of business and at market rates. These
directors are not involved in the day to day operational decision
making of the Company or the related entities. The dollar
value of the transactions between Peyto and the related reporting
entities is summarized below:
Expense |
Accounts Payable |
Year ended December 31 |
As at December 31 |
2017 |
2016 |
2017 |
2016 |
671.7 |
1007.0 |
549.2 |
700.0 |
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 $2.0 million is included
in general and administrative expenses and $7.2 million in market
and reserves based bonus relating to key management personnel for
the year 2017 (2016 - $2.0 million in general and administrative
and $12.4 million in market and reserves based bonus).
13. Commitments
In addition to those recorded on the Company’s balance sheet,
the following is a summary of Peyto’s contractual obligations and
commitments as at December 31, 2017:
|
2018 |
2019 |
2020 |
2021 |
2022 |
Thereafter |
Interest payments (1) |
22,085 |
19,890 |
17,695 |
12,295 |
12,295 |
14,350 |
Transportation commitments |
39,199 |
34,467 |
24,049 |
20,522 |
20,238 |
59,251 |
Operating leases |
2,242 |
2,242 |
2,242 |
2,242 |
2,317 |
9,269 |
Methanol |
1,279 |
- |
- |
- |
- |
- |
Total |
64,805 |
56,599 |
43,986 |
35,059 |
34,850 |
82,870 |
(1) Fixed interest payments on senior
unsecured notes
14. Contingencies
On October 1, 2013, two shareholders (the
"Plaintiffs") of Poseidon Concepts Corp. ("Poseidon") filed an
application to seek leave of the Alberta Court of Queen's Bench
(the "Court") to pursue a class action lawsuit against the Company,
as a successor to new Open Range Energy Corp. ("New Open Range")
(the “Poseidon Shareholder Application”). The proposed action
contains various claims relating to alleged misrepresentations in
disclosure documents of Poseidon (not New Open Range), which claims
are also alleged in class action lawsuits filed in Alberta,
Ontario, and Quebec earlier in 2013 against Poseidon and certain of
its current and former directors and officers, and underwriters
involved in the public offering of common shares of Poseidon
completed in February 2012. The proposed class action
seeks various declarations and damages including compensatory
damages which the Plaintiffs estimate at $651 million and
punitive damages which the Plaintiffs estimate at $10 million,
which damage amounts appear to be duplicative of damage amounts
claimed in the class actions against Poseidon, certain of its
current and former directors and officers, and underwriters.
New Open Range was incorporated on
September 14, 2011 solely for purposes of participating in a
plan of arrangement with Poseidon (formerly named Open Range Energy
Corp. ("Old Open Range")), which was completed on November 1,
2011. Pursuant to such arrangement, Poseidon completed a
corporate reorganization resulting in two separate publicly-traded
companies: Poseidon, which continued to carry on the energy service
and supply business; and New Open Range, which carried on
Poseidon's former oil and gas exploration and production
business. Peyto acquired all of the issued and outstanding
common shares of New Open Range on August 14, 2012. On
April 9, 2013, Poseidon obtained creditor protection under the
Companies' Creditor Protection Act.
On October 31, 2013, Poseidon filed a
lawsuit with the Court naming the Company as a co-defendant along
with the former directors and officers of Poseidon, the former
directors and officers of Old Open Range and the former directors
and officers of New Open Range (the “Poseidon Action”).
Poseidon claims, among other things, that the Company is
vicariously liable for the alleged wrongful acts and breaches of
duty of the directors, officers and employees of New Open
Range.
On September 24, 2014 Poseidon amended its claim
in the Poseidon Action to add Poseidon’s auditor, KPMG LLP
(“KPMG”), as a defendant.
On May 4, 2016, KPMG issued a third party claim
in the Poseidon Action against Poseidon’s former officers and
directors and Peyto for any liability KPMG is determined to have to
Poseidon. Peyto is not required to deliver a defence to this
claim at this time.
On July 3, 2014, the Plaintiffs filed a
lawsuit with the Court against KPMG LLP, Poseidon's and Old Open
Range's former auditors, making allegations substantially similar
to those in the other claims (the “KPMG Poseidon Shareholder KPMG
Action”). On July 29, 2014, KPMG LLP filed a statement
of defence and a third party claim against Poseidon, the Company
and the former directors and officers of Poseidon. The third
party claim seeks, among other things, an indemnity, or
alternatively contribution, from the third party defendants with
respect to any judgment awarded against KPMG LLP.
The allegations against New Open Range contained
in the claims described above are based on factual matters that
pre-existed the Company’s acquisition of New Open Range. The
Company has not yet been required to defend either of the actions.
If it is required to defend the actions, the Company intends to
aggressively protect its interests and the interests of its
Shareholders and will seek all available legal remedies in
defending the actions.
15. Subsequent
Events
On January 2, 2018, the Company closed an
issuance of CDN $100 million of senior unsecured notes. The notes
were issued by way of a private placement, pursuant to a note
purchase agreement and a note purchase and private shelf agreement
and rank equally with Peyto's obligations under its bank facility
and existing note purchase agreements. The notes have a coupon rate
of 3.95% and mature on January 2, 2028. Interest will be paid
semi-annually in arrears. Proceeds from the notes were used to
repay a portion of Peyto's outstanding bank debt.
Officers
Darren
Gee President and Chief Executive Officer |
Tim
LouieVice President, Land |
|
|
Scott
Robinson Executive Vice President New Ventures & Director
|
David
Thomas Vice President, Exploration |
|
|
Kathy
Turgeon Vice President, Finance and Chief Financial Officer
|
Jean-Paul
Lachance Vice President, Engineering & COO |
|
|
Lee
Curran Vice President, Drilling and Completions |
Stephen
Chetner Corporate Secretary |
|
|
Todd
Burdick Vice President, Production |
|
DirectorsDon Gray,
ChairmanStephen ChetnerBrian DavisMichael MacBean, Lead Independent
DirectorDarren GeeGregory FletcherScott Robinson
AuditorsDeloitte LLP
SolicitorsBurnet, Duckworth
& Palmer LLP
BankersBank of MontrealBank of
Tokyo-Mitsubishi UFJ, Ltd., Canada BranchRoyal Bank of
CanadaCanadian Imperial Bank of CommerceThe Toronto-Dominion
Bank
Bank of Nova ScotiaAlberta Treasury
BranchesCanadian Western BankNational BankWells Fargo
Transfer
AgentComputershare
Head Office300, 600 – 3 Avenue
SWCalgary, ABT2P 0G5
Phone: |
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403.261.6081 |
Fax: |
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403.451.4100 |
Web: |
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www.peyto.com |
Stock Listing
Symbol: PEY.TO |
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