2017
ANNUAL
REPORT
TSX | PONY
1
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2
Table of
Contents
1
2
6
32
33
34
38
65
Financial and Operational Highlights
Message to Shareholders
Management's Discussion and Analysis
Management's Responsibility
for Consolidated Financial Statements
Independent Auditors' Report
Consolidated Financial Statements
Notes to Consolidated Financial Statements
Corporate Information
“Come Hell or High Water”
- By Paul Van Ginkel
No matter the weather, the drivers and horses always show up to
the race ready to run. This painting symbolizes both the energy
industry and our western Canadian way of life. Many likely recall
the Rangeland Derby Chuckwagon Races on that first night of the
2013 Calgary Stampede, the year of the massive flood that swept
Calgary. Calgarians feared that the Stampede might not happen
that year. To everyone’s amazement, the Stampede managed
to repair and reconstruct the infield racetrack in a very short
period of time. No other city in the world could have pulled off
such a feat, but Calgary did. It was truly inspiring to watch the
drivers and the horses line up, chomping at their bits and ready to
go! Nobody reflects this spirit better than Gary Gorst, the driver
featured in “Come Hell or High Water” and sponsored jointly by
Painted Pony and AltaGas in the 2017 and the 2018 Rangeland
Derby Chuckwagon Races. This same spirit of perseverance
through adversity is part of everything we do at Painted Pony.
Regardless of the headwinds, we work relentlessly for the best
outcomes for stakeholders.
Cover painting "Come Hell or High Water", oil on canvas by Paul Van Ginkel
www.paulvanginkel.com
Corporate
Profile
Painted Pony is a publicly-traded natural
gas corporation based in Western Canada.
The Corporation is primarily focused on the
development of natural gas and natural gas
liquids from the Montney formation in Northeast
British Columbia. Painted Pony's common shares
trade on the Toronto Stock Exchange under the
symbol “PONY”.
10
Annual
General
Meeting
Painted Pony Energy Ltd. invites shareholders and
interested parties to attend its Annual General
Meeting to be held in the Bennett Room at the
Ranchmen's Club, 710 – 13th Avenue SW, Calgary,
Alberta, at 3:00 pm (Calgary time), on May 10, 2018.
Shareholders not attending are encouraged
to complete the form of proxy and deliver it in
accordance with the instructions therein at their
earliest convenience.
Financial and
Operating Highlights
Year Ended December 31
$ millions, except per share and shares outstanding
Financial
Petroleum and natural gas revenue (1)
Cash flow from operating activities
Per share – basic (3)
Per share – diluted (4)
Adjusted funds flow from operations (2)
Per share – basic (3)
Per share – diluted (4)
Net income (loss) and comprehensive income (loss)
Per share – basic (3)
Per share – diluted (4)
Capital expenditures
Working capital (deficiency) (5)
Bank debt
Senior notes
Convertible debentures - liability
Net debt (6)
Total assets
Shares outstanding (millions)
Basic weighted-average shares (millions)
Fully diluted weighted-average shares (millions)
Operating
Daily production volumes
Natural gas (MMcf/d)
Natural gas liquids (bbls/d)
Total (MMcfe/d)
Total (boe/d)
Realized commodity prices
Natural gas ($/Mcf)
Natural gas liquids ($/bbl)
Total ($/Mcfe)
Operating netbacks ($/Mcfe) (7)
2017
249.2
106.9
0.76
0.74
107.5
0.76
0.75
122.4
0.87
0.85
302.6
33.0
149.2
141.6
44.9
363.9
2,031.6
161.0
140.7
144.1
235.8
3,587
257.3
42,882
2.13
50.53
2.65
2.01
2016
121.6
44.7
0.45
0.45
55.6
0.56
0.56
(51.9)
(0.52)
(0.52)
204.4
(73.6)
200.8
–
–
228.5
1,337.0
100.2
100.1
100.1
129.9
1,557
139.2
23,204
2.04
43.49
2.39
1.73
Change
105%
139%
69%
64%
93%
36%
34%
–
–
–
48%
–
(26%)
–
–
59%
52%
61%
41%
44%
82%
130%
85%
85%
4%
16%
11%
16%
1. Before royalties.
2.
Adjusted funds flow from operations and adjusted funds flow from operations per share (basic and diluted) are non-GAAP measures used to represent cash
flow from operating activities before the effects of changes in non-cash working capital, share unit expense and decommissioning expenditures. Adjusted
funds flow from operations per share is calculated by dividing adjusted funds flow from operations by the weighted average number of basic or diluted
shares outstanding in the period. See “Non-GAAP Measures”.
3. Basic per share information is calculated on the basis of the weighted average number of shares outstanding in the period.
4. Diluted per share information reflects the potential dilutive effect of stock options and convertible debentures.
5. Working capital deficiency is a non-GAAP measure calculated as current assets less current liabilities. See “Non-GAAP Measures”.
6.
Net debt is a non-GAAP measure calculated as bank debt, senior notes, liability portion of convertible debentures, and working capital deficiency, adjusted
for the net current portion of fair value of risk management contracts and current portion of finance lease obligation.
Operating netbacks is a non-GAAP measure calculated on a per unit basis as natural gas and natural gas liquids revenues, adjusted for realized gains or
losses on risk management, less royalties, operating expenses and transportation costs. See “Non-GAAP Measures” and “Operating Netbacks”.
7.
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
1
Message
to Shareholders
As 2017 drew to a close, the collapse of
natural gas prices in the summer and fall at
the main Canadian sales hub at AECO, as well
as in the forward natural gas strip price at
AECO, dominated the industry. In response to
this, companies reduced capital investment.
Production forecasts are reflective of the
weakness in future strip prices. The current
forward strip remains well below $2.00 at the
AECO sales hub for the next several years.
The forecasted reduction in capital investment
by industry and the expected shrinking
production volumes should begin to reverse
the severe price decline and improve the future
price of natural gas in western Canada, but the
timeline is unclear. As such, we will continue to
fortify our business through diversified market
access, capital spending limited to internally
generated cash flow, and reducing
or maintaining debt levels.
2017 was a notable year
as we took several major
steps to enhance the size and
quality of our asset base while
maintaining our financial
flexibility. We acquired UGR Blair Creek
Ltd. (“UGR”) in an all-share deal, raised
$111 million in an equity financing at
$5.60 per share, and diversified our debt
capital through a $200 million private
placement debt financing. We reached
record annual average daily production of
257 MMcfe/d (42,882 boe/d) and signed a
14-year contract with Methanex Corporation
for delivery of natural gas to their Methanol
plant in Alberta. We achieved record adjusted
funds flow from operations of $108 million
($0.76 per share). Finally, we ended the year
with record Proved Plus Probable reserves of
6.9 Tcfe, which equates to over 1.1 billion boe,
and have a net present value of $3.3 billion
using a 10% discount rate using pricing from
independent qualified reserves evaluators,
GLJ Petroleum Consultants Ltd. (“GLJ”).
Production Growth
I am pleased to report that annual average
daily production for 2017 was 257 MMcfe/d or
42,882 boe/d, representing an increase of 85%
over 2016 annual average daily production of
139 MMcfe/d or 23,204 boe/d. This production
growth is particularly notable when considering
that fourth quarter 2017 production volumes
were impacted by approximately 48 MMcfe/d
or 8,000 boe/d of voluntary pricing-related
production shut-ins.
2
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
3
“Tough times
“
don’t last, tough
people do
-- Robert Schuller
Along with the increase in annual average daily
production volumes, we also saw the growth
in natural gas liquids (“NGL”) which increased
130% to 3,587 bbls/d during 2017 compared
to 1,557 bbls/d during 2016. The increase in
both absolute production volumes and NGL
production volumes reflects the impact of a
full year of liquids-rich processing capacity of
the Townsend Facility that came on-line during
the third quarter of 2016 and the 99 MMcf/d
expansion that became operational in the third
quarter of 2017. Although liquids production
was 8% of the total annual average daily
production volumes, liquids revenue was 27%
of total revenue during 2017.
Capital Expenditures
The 2017 capital program was the largest and
most ambitious capital program in Painted
Pony’s history. We executed the 2017 capital
plan efficiently and with discipline, meeting
production growth targets from spending $303
million during the year compared to spending
guidance of $315 million. We drilled 52 net
wells and completed 51 net wells, supported
by minor investments into associated facilities
and infrastructure.
2017 was our most active year to date, and we
maintained our high standards of workplace
and environmental safety. In addition to a year
without a single lost-time injury, we conducted
a test of our Emergency Response Plan in
conjunction with the British Columbia Oil and
Gas Commission and received a score of 92%.
It is a testament to the high regard we place
on workplace and environmental safety while
achieving our operational goals at Painted
Pony.
Acquisition of UGR Blair Creek
On May 16, 2017 we closed the acquisition of
UGR Blair Creek Ltd. in an all-share deal that
resulted in an increase of more than 50% to
our Montney acreage to more than 200,000
acres. From the beginning, we were partners
with UGR in several key sections of land
and shared working interest in a number of
producing wells. In fact, of UGR’s 36 producing
wells, 20 of them were drilled by Painted Pony.
We long-believed that UGR would be a logical
fit into Painted Pony’s acreage. Through the
consolidation of our lands with UGR’s 100
net sections, we now have a larger and more
concentrated position in what we believe to
be the best Montney acreage in the play. This
also increased our working interest to 94%
from 86% previously. UGR’s underutilized
gas processing facilities, combined with the
2
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
3
85% Growth in
Annual Average Daily
Production Volumes
AltaGas Townsend Facility, ensures we have all
the necessary capacity to process our current
natural gas production volumes and room for
expansion. We firmly believe the acquisition of
UGR will provide long-term value through our
expanded asset base and will deliver value to
shareholders for years to come.
Reserves Growth
The impact of our successful 2017 capital
program combined with the acquisition of
UGR, increased our year-end 2017 Proved
Plus Probable reserves by 40% to 6.9 Tcfe
or over 1.1 billion boe. We also increased
our Total Proved reserves by 17% to 3.1 Tcfe
as at year-end 2017. Our Proved Developed
Producing reserves grew by 64% to 797 Bcfe,
over 130 MMboe, and carried a value at year-
end 2017 of $905 million ($5.62 per share) at
a 10% discount rate using pricing from GLJ.
While we believe reserve totals and value are
important, the cost of finding the reserves is
equally as important. I am pleased that our
finding, development and acquisition ("FD&A")
cost on Total Proved reserves in 2017 produced
a 1.6 times recycle ratio, inclusive of changes
in future development costs. This meant that
were generating 1.6 times as much cash flow
per Mcfe than what it was costing us to find and
develop new reserves to replace those which
we produce. We believe that the strength of this
key measure highlights the efficiency of our
capital spending and demonstrates the health
of our business.
Sales Diversification
As our production volumes were increasing
three years ago, we knew we needed to
diversify our marketing efforts into as many
sales regions and pricing hubs as possible to
protect Painted Pony from regional pricing
volatility and increase the price received for
our natural gas. As we begin 2018, we continue
to see the benefits from the execution of this
strategy. We have successfully assembled
a diversified marketing portfolio consisting
of fixed-price contracts, direct-to-customer
physical contracts, basis contracts and financial
hedges, across several pricing hubs. Combined,
this portfolio provides the price protection from
commodity price volatility necessary in this
environment.
Our firm transportation on the Enbridge system
using the T-North line is now 357 MMcf/d, of
which 174 MMcf/d has firm receipt into the
NGTL system at Groundbirch via the TCPL
4
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
5
Daily Production
for 2017 averaged
257MMcfe/day
(42,882 boe/d)
Canada’s west coast. If approved, these projects
are several years away from completion but
will provide a much-needed diversification of
markets for Canadian natural gas.
2017 was a year of capital discipline,
diversification of sales, and significant growth.
While there is much of which to be proud, many
challenges remain. I am confident we will
weather this storm caused by low natural gas
prices and emerge a stronger company, well-
positioned for future success and profitability.
Finally, a sincere thank you to the staff and
Board of Directors at Painted Pony. We also
would like to thank our service providers and
shareholders for your continued support of
Painted Pony Energy.
“signed”
Patrick R. Ward
President and Chief Executive Officer
March 30, 2018
Towerbirch Expansion Project. This access is
complimented with 43 MMcf/d which continues
moving east to be delivered into the Dawn
market in southern Ontario. The volumes
delivered into the Dawn market will increase
to 81 MMcf/d by November 2019. In addition to
volumes sold into the Dawn market we have
diversified our sales exposure to cover 55%
of our forecasted 2018 production volumes on
fixed-price contracts (hedges) at a blended
price of $3.76/Mcfe, capturing prices much
higher than current spot prices in western
Canada. Combined, we have natural gas pricing
exposure to AECO, Station 2, Sumas, Dawn, and
NYMEX. Liquids volumes are sold both on spot
prices as well as fixed price contracts. We have
greatly reduced the risk of commodity price
volatility on our 2018 revenue.
2018 and Forward
The prospect of investment into a number of
liquefied natural gas (“LNG”) export facilities on
the west coast and the east coast seem more
likely now than in recent years. We hope to
have clarity on some of these potential projects
in the coming months. Due to the size and
scale of our production and reserves, we are
well-positioned to provide natural gas for LNG
projects such as the ones being considered on
4
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
5
MANAGEMENT’S DISCUSSION AND ANALYSIS
The following Management’s Discussion and Analysis (“MD&A”) of the consolidated financial results of Painted Pony
Energy Ltd. (“Painted Pony” or the “Corporation”) should be read in conjunction with the consolidated financial
statements and related notes thereto for the years ended December 31, 2017 and December 31, 2016. This
commentary is dated March 7, 2018.
The annual consolidated financial statements have been prepared in accordance with International Financial
Reporting Standards (“IFRS”). The financial data presented is in accordance with IFRS in Canadian dollars, except
where indicated otherwise. These documents and additional information about Painted Pony, including the Annual
Information Form (“AIF”) for the year ended December 31, 2017, are available under the Corporation’s profile on
SEDAR at www.sedar.com and on the Corporation’s website at www.paintedpony.ca.
BUSINESS OF THE CORPORATION
Painted Pony is a publicly traded corporation focused on the production of natural gas and natural gas liquids (“NGLs”)
from the Montney formation in northeast British Columbia. The common shares of Painted Pony (“Common Shares”)
trade on the Toronto Stock Exchange (“TSX”) under the symbol “PONY”. The Corporation’s head office is located
at Suite 1800, 736 - 6th Avenue SW, Calgary, Alberta. During the second quarter of 2017, the Corporation changed
its name from Painted Pony Petroleum Ltd., and its stock trading symbol from "PPY".
NON-GAAP MEASURES
This MD&A contains the terms “adjusted funds flow from operations”, “adjusted funds flow from operations per share”,
“adjusted funds flow from operations per Mcfe”, “working capital deficiency”, “net debt” and “operating netbacks”,
which do not have standardized meanings prescribed by IFRS and therefore may not be comparable with the
calculation of similar measures presented by other issuers.
Management uses “adjusted funds flow from operations” to analyze operating performance and considers adjusted
funds flow from operations to be a key measure as it demonstrates the Corporation’s ability to generate the cash
necessary to fund future capital investment and to repay debt. Adjusted funds flow from operations denotes cash
flow from operating activities before the effects of changes in non-cash working capital, share unit expense and
decommissioning expenditures. “Adjusted funds flow from operations per share” is calculated using the basic and
diluted weighted average number of shares for the period. “Adjusted funds flow from operations per Mcfe” is calculated
using the average production volumes for the period. For the year ended December 31, 2017, adjusted funds flow
from operations, adjusted funds flow from operations per share and adjusted funds flow from operations per Mcfe
are presented net of UGR acquisition costs. These terms should not be considered alternatives to, or more meaningful
than, cash flows from operating activities as determined in accordance with IFRS as an indicator of the Corporation’s
performance. The Corporation reconciles adjusted funds flow from operations to cash flows from operating activities,
which is the most directly comparable measure calculated in accordance with IFRS, as follows:
Cash Flows from Operating Activities and Adjusted Funds Flow from Operations
($000s, except per share)
Cash flows from operating activities
Changes in non-cash working capital
Share unit expense (recovery)
Decommissioning expenditures
Adjusted funds flow from operations
Adjusted funds flow from operations per share ($/share):
Basic
Diluted
Three months ended
December 31,
Years ended
December 31,
2017
27,417
8,212
(399)
—
35,230
0.22
0.21
2016
21,859
3,355
1,284
3
26,501
0.26
0.26
2017
106,917
2,287
(1,724)
—
107,480
0.76
0.75
2016
44,658
7,931
2,914
102
55,605
0.56
0.56
2
6
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
7
Management uses “working capital deficiency” and “net debt” as useful supplemental measures of the liquidity of
the Corporation. Working capital deficiency is calculated as current assets less current liabilities. Net debt is calculated
as bank debt, senior notes, liability portion of convertible debentures, and working capital deficiency, adjusted for
the net current portion of fair value of risk management contracts and current portion of finance lease obligation.
These terms should not be considered alternatives to, or more meaningful than, current and long-term debt as
determined in accordance with IFRS. The following table summarizes Painted Pony’s calculations of working capital
deficiency and net debt:
Working Capital Deficiency and Net Debt
As at ($000s)
Current assets
Current liabilities
Working capital (deficiency)
Current portion of fair value of risk management contracts (net)
Current portion of finance lease obligation
Bank debt
Senior notes
Convertible debentures - liability
Net debt
December 31, 2017
105,795
(72,770)
33,025
(64,463)
3,282
(149,228)
(141,613)
(44,887)
(363,884)
December 31, 2016
30,677
(104,324)
(73,647)
46,020
—
(200,836)
—
—
(228,463)
Management uses “operating netbacks” as a supplemental measure of the Corporation’s profitability relative to
commodity prices. Operating netbacks are calculated on a per unit basis as natural gas and NGL revenues, adjusted
for realized gains or losses on risk management, less royalties, operating expenses and transportation costs. This
term should not be considered an alternative to, or more meaningful than net income (loss) and comprehensive
income (loss) as determined in accordance with IFRS. Please refer to “Operating Netbacks” for the calculation of
this measure.
RESULTS OF OPERATIONS - OVERVIEW
The Corporation successfully closed the acquisition (the “UGR acquisition”) of all of the issued and outstanding
shares of UGR Blair Creek Ltd. (“UGR”) during 2017, in exchange for the issuance of 41.0 million Common Shares
of the Corporation to the vendor, the assumption by the Corporation of UGR’s bank debt of approximately $48.2
million on closing and the payment of certain acquisition costs. The price of the Corporation’s Common Shares at
the close of trading on the closing date of the UGR acquisition, May 16, 2017, was $5.37 per common share, resulting
in total share consideration of $220.2 million. The UGR acquisition is a strategic expansion of the Corporation's
Montney project in northeast British Columbia, providing for an increase of the Corporation's land base, natural gas
processing infrastructure, reserves and drilling inventory.
During the year ended December 31, 2017, the Corporation closed a transaction with Magnetar Capital to issue a
total of $200 million of term debt consisting of $150 million of senior unsecured notes and $50 million of unsecured
subordinated convertible debentures. The Corporation received $188.8 million of cash, net of financing fees, which
was used to repay bank debt and fund the Corporation's capital program.
A public offering of 19.8 million Common Shares was completed during 2017, at a price of $5.60 per Common Share
for aggregate gross proceeds of approximately $111.0 million (including the exercise in full of the over-allotment
option granted to the underwriters).
As part of the Corporation's strategy to enhance realized natural gas commodity prices through innovative sales
contracts, Painted Pony entered into a long-term agreement in 2017 to deliver natural gas (the “Agreement”) to
Methanex Corporation (“Methanex”) under a fixed price US dollar denominated contract. Painted Pony will supply
the majority of the natural gas required for Methanex’s existing 600,000 tonne methanol plant in Medicine Hat, Alberta
for a term of 14 years. Deliveries under the Agreement will commence in 2018 and contracted quantities will be
approximately 10 MMcf/d (10,000 MMBtu/d) in 2018, increasing over time to approximately 50 MMcf/d
(50,000 MMBtu/d) in 2023.
3
6
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
7
The Townsend Phase 2 expansion commenced commercial operation in the fourth quarter of 2017. The Corporation
has the right to the full 99 MMcf/d of firm capacity of the new gas processing train at Townsend, in respect of which
there is a take or pay obligation on production volumes delivered to the facility of 90 MMcf/d commencing in the first
quarter of 2018. The Townsend Phase 2 expansion was recorded as a finance lease, recording the asset, representing
the total estimated construction cost of the Townsend Phase 2 expansion and related pipeline infrastructure of $130
million, with a corresponding obligation on the statement of financial position. The efficiencies associated with this
expansion are expected to reduce the fixed capital fee on a per mcf basis, paid by Painted Pony at the Townsend
Phase 1 and 2 complex, by approximately 20% after commencement of the Townsend Phase 2 expansion take or
pay.
Results of operations for the year highlight an increase in production volumes through both organic growth and the
acquisition of UGR. With an increase in volumes of 85%, higher realized commodity prices and realized gains on
risk management contracts, the Corporation increased its adjusted funds flow from operations for 2017 by 93% to
$107.5 million ($0.76/share), compared to 2016 adjusted funds flow from operations of $55.6 million ($0.56/share).
Although commodity prices in the first and second quarter of 2017 recovered from comparable period commodity
prices in 2016, the third and fourth quarters of 2017 saw price reductions. Painted Pony’s exposure to low commodity
prices in 2017 was mitigated by risk management contracts that resulted in a $44.0 million realized gain. After the
impact of realized gains on risk management contracts of $0.47/Mcfe, Painted Pony’s operating netback was
$2.01/Mcfe, an increase of 16% over the previous year operating netback of $1.73/Mcfe. Painted Pony’s operating
netback for the three months ended December 31, 2017 was $2.05/Mcfe, comparable to the fourth quarter of 2016
operating netback of $2.09/Mcfe. For 2018, the Corporation has executed fixed price risk management contracts on
204.7 MMcf/d of natural gas and 3,400 bbl/d of NGL production. The Corporation continues to expand into new
markets as part of its long term sales point diversification strategy, and is now delivering a significant portion of its
natural gas volumes into the AECO, Dawn and Sumas markets. In addition, the Corporation has entered into fixed
price contracts for physical delivery of natural gas priced at AECO or Sumas, less fixed differentials.
The capital program for 2017 of $302.6 million included 52 (52.0 net) Montney natural gas wells drilled and 51 (51.0
net) Montney natural gas wells completed, as well as associated facilities infrastructure. During the fourth quarter of
2017, Painted Pony drilled 7 (7.0 net) and completed 15 (15.0 net) Montney natural gas wells, and executed a capital
program of $62.5 million including associated facilities infrastructure spending. The planned 2018 capital program
is currently anticipated to include 29 (29.0 net) Montney horizontal natural gas wells drilled and 31 (31.0 net)
completed.
At December 31, 2017, the Corporation's syndicated credit facilities consisted of available credit facilities of $450
million.
CASH FLOWS FROM OPERATING ACTIVITIES, ADJUSTED FUNDS FLOW FROM OPERATIONS AND NET
INCOME
For the fourth quarter of 2017, cash flows from operating activities and adjusted funds flow from operations increased
to $27.4 million and $35.2 million, respectively, compared to cash flows from operating activities of $21.9 million and
adjusted funds flow from operations of $26.5 million in the fourth quarter of 2016. The increases in both cash flows
from operating activities and adjusted funds flow from operations were primarily the result of an overall increase in
average production of 43%.
For the year ended December 31, 2017, cash flows from operating activities and adjusted funds flow from operations
increased to $106.9 million and $107.5 million respectively, compared to cash flows from operating activities of $44.7
million and adjusted funds flow from operations of $55.6 million in the year ended December 31, 2016. Increases
in both cash flows from operating activities and adjusted funds flow from operations for the year ended December 31,
2017 compared to the year ended December 31, 2016, are as a result of an 85% increase in production volumes,
a 24% increase in per unit realized gains on risk management contracts, and an 11% increase in realized commodity
prices, offset by a 7% increase in costs per unit.
For the fourth quarter of 2017, the Corporation generated income and comprehensive income of $37.1 million,
positively impacted by an unrealized gain on risk management contracts and higher revenue due to increased
production. This compares to a net loss and comprehensive loss of $27.8 million for the quarter ended December 31,
4
8
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
9
2016. Excluding the unrealized gain on risk management contracts, income before taxes was $9.2 million for the
quarter ended December 31, 2017, compared to income before taxes of $8.0 million for the quarter ended
December 31, 2016.
For the year ended December 31, 2017, the Corporation generated income and comprehensive income of $122.4
million positively impacted by an unrealized gain on risk management contracts, partially offset by UGR acquisition
costs. This compares to a net loss and comprehensive loss of $51.9 million for the year ended December 31, 2016.
Excluding the unrealized gain (loss) on risk management contracts and UGR acquisition costs, income before taxes
was $26.8 million for the year ended December 31, 2017, compared to $5.9 million for the year ended December 31,
2016.
AVERAGE DAILY PRODUCTION
Three months ended December 31,
Year ended December 31,
Natural Gas (Mcf/d)
NGLs (bbls/d)
Total (Mcfe/d)
Total (boe/d)
287,811
4,575
315,264
52,544
2017 % of total
91
9
2016 % of total
91
9
201,111
3,177
220,170
36,695
100
100
100
100
2017 % of total
235,767
3,587
257,292
42,882
92
8
100
100
2016 % of total
93
7
100
129,881
1,557
139,224
23,204
100
Production volumes for the three months and year ended December 31, 2017 increased by 43% and 85%,
respectively, compared to the three months and year ended December 31, 2016. The increase in NGL volumes
reflects a greater focus on the liquids-rich processing capacity of the Townsend Facility. The production volume
increase during the period was driven by production additions from successful new drills in the Blair Creek, Townsend
and Daiber areas, the commissioning of the Townsend Facility expansion in the third quarter of 2016, and the UGR
acquisition. For the fourth quarter ended December 31, 2017, the Corporation voluntarily shut-in approximately 48
MMcfe/d (8,000 boe/d) of production due to commodity pricing declines.
PETROLEUM AND NATURAL GAS REVENUE
($000s)
Natural Gas
NGLs
Total
Three months ended
December 31,
2016
51,529
43,883
2017
Years ended
December 31,
2016
96,803
2017
183,030
23,915
67,798
13,626
65,155
66,156
249,186
24,777
121,580
Petroleum and natural gas revenue totaled $67.8 million for the three months ended December 31, 2017, representing
a 4% increase from the fourth quarter 2016 revenue of $65.2 million. The increase in quarterly revenue is driven by
a 43% increase in average production volumes partially offset by a 27% decline in realized commodity pricing.
During the year ended December 31, 2017, petroleum and natural gas revenue increased by 105% to $249.2 million
as a result of an 85% increase in average production volumes as well as an 11% increase in realized commodity
pricing.
8
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
9
5
Commodity Prices
Average Benchmark Prices:
Natural Gas
NYMEX (US$/MMBtu)
AECO, daily (5A) ($/Mcf)
Westcoast Station 2 ($/Mcf)
Dawn ($/Mcf)
WTI (US$/bbl)
Crude Oil
Exchange rate (US$/Cdn$)
Realized Commodity Prices Before Commodity Risk Management:
Natural Gas ($/Mcf)
NGLs ($/bbl)
Total ($/Mcfe)
1.66
56.81
2.34
Three months ended
December 31,
2016
3.18
3.12
2.27
4.22
49.29
0.75
2017
2.92
1.69
0.56
3.72
55.40
0.79
Years ended
December 31,
2016
2.55
2.17
1.64
3.39
43.48
0.76
2017
3.02
2.16
1.56
3.95
50.96
0.77
2.78
46.62
3.22
2.13
50.53
2.65
2.04
43.49
2.39
During the three months and year ended December 31, 2017, the Corporation realized natural gas prices of
$1.66/Mcf and $2.13/Mcf, respectively, which represents a decrease of 40% and an increase of 4% over the three
months and year ended December 31, 2016 realized natural gas prices of $2.78/Mcf and $2.04/Mcf, respectively.
The increase during the year ended December 31, 2017 reflects stable or higher spot natural gas benchmark prices
on most indexes, compared to the same period in 2016, as well as the impact of the Corporation’s physical fixed
price contracts. The decrease in realized natural gas prices for the three months ended December 31, 2017 compared
to the three months ended December 31, 2016 resulted from a combination of market factors, including temporary
disruptions to the natural gas pipeline system, as well as other major supply and demand issues in North America.
As part of the Corporation’s long term market diversification strategy, Painted Pony reduced its exposure to Daily
Station 2 pricing to less than 10% in the last half of 2017. In 2018, exposure to Station 2 is expected to average
below 15%. Diversification away from Station 2 has been achieved by entering into financial and physical
commitments, including contracting for transportation outside of the British Columbia market.
For the three months ended December 31, 2017, approximately 44% of the Corporation’s NGL volumes were
condensate, which received an average price of $73.27/bbl, representing a premium of 5% to the WTI reference
price. For the year ended December 31, 2017, approximately 46% of the Corporation’s NGL volumes were
condensate, which received an average price of $67.99/bbl, representing a premium of 4% to the WTI reference
price.
For 2018, the Corporation expects to receive a realized natural gas price that represents a premium to the benchmark
Westcoast Station 2 price and comparable with the AECO (5A) benchmark price. The majority of the volatility
experienced by the Corporation in commodity pricing in 2017 has been mitigated for 2018 by the commodity risk
management contracts described below, as well as the completion of the Towerbirch pipeline expansion at
Groundbirch, allocating Painted Pony an increase in direct to AECO production of 130MMcf/d.
Financial Risk Management
The Corporation uses financial derivative contracts to mitigate some of its exposure to commodity price, foreign
exchange and interest rate risk. The use of these transactions is governed by and is subject to risk management
policies established by the Board of Directors of the Corporation (the "Board"). These instruments are not used for
trading or speculative purposes. The Corporation has not designated its financial derivative contracts as effective
accounting hedges, even though the Corporation considers all financial derivative contracts to be effective economic
hedges. As a result, all such contracts are recorded at fair value on the consolidated statement of financial position,
with changes in the fair value being recognized as an unrealized gain or loss on the consolidated statement of
operations.
6
10
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
11
Realized Gain (Loss) on Risk Management Contracts
Realized gain (loss) on risk management contracts ($000s)
Per unit ($/Mcfe)
Three months ended
December 31,
Years ended
December 31,
2017
24,156
0.83
2016
(1,632)
(0.09)
2017
44,002
0.47
2016
19,912
0.38
The Corporation’s method of determining the fair values of derivative financial instruments is disclosed in note 17 to
the Annual Consolidated Financial Statements.
At December 31, 2017, the Corporation held commodity risk management contracts summarized as follows:
Financial AECO Natural Gas Contracts
Options traded
AECO Fixed Price Swap
AECO Fixed Price Swap
AECO Fixed Price Swap
AECO Fixed Price Swap
AECO Fixed Price Swap
AECO Fixed Price Swap
AECO Fixed Price Swap
AECO Fixed Price Swap
AECO Fixed Price Swap
AECO Fixed Price Swap
AECO Fixed Price Swap
AECO Fixed Price Swap
AECO Fixed Price Swap
AECO Fixed Price Swap
AECO Fixed Price Swap
AECO Call Option Sold
AECO Call Option Sold
Term
January 2018 - September 2018
January 2018 - March 2018
January 2018 - September 2018
January 2018 - September 2018
January 2018 - June 2018
January 2018 - December 2018
January 2018 - June 2019
January 2018 - June 2018
January 2018 - June 2018
January 2018 - March 2018
January 2018 - December 2018
January 2018 - December 2018
January 2018 - December 2018
April 2018 - June 2019
April 2018 - March 2019
January 2018 - December 2019
January 2018 - December 2019
Financial Dawn Natural Gas Contracts
Options traded
Dawn Fixed Price Swap
Dawn Fixed Price Swap
Term
April 2018 - March 2019
April 2018 - March 2019
Financial NYMEX Basis Differential Contracts
Options traded
NYMEX-AECO Basis Swap
NYMEX-AECO Basis Swap
NYMEX-Dawn Basis Swap
Term
April 2018 - October 2018
April 2019 - September 2021
January 2018 - December 2018
7
Volume
(GJ/d)
6,000
10,000
10,000
10,000
6,000
6,000
8,000
10,000
5,000
10,000
10,000
10,000
10,000
10,000
10,000
10,000
15,000
Price
(CDN$/GJ)
3.07
3.18
2.84
2.85
3.03
2.95
2.66
2.88
3.01
3.16
2.57
2.56
2.32
2.62
2.32
2.80
2.93
Volume
(GJ/d)
10,000
10,000
Price
(CDN$/GJ)
3.47
3.50
Volume
(MMBtu/d)
10,000
10,000
10,000
Price
(NYMEX less
US$/MMBtu)
1.14
1.14
0.11
10
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
11
Financial Station 2 Natural Gas Contracts
Options traded
Stn. 2 Fixed Price Swap
Stn. 2 Fixed Price Swap
Stn. 2 Fixed Price Swap
Stn. 2 Fixed Price Swap
Stn. 2 Fixed Price Swap
Stn. 2 Fixed Price Swap
Stn. 2 Fixed Price Swap
Stn. 2 Fixed Price Swap
Stn. 2 Fixed Price Swap
Stn. 2 Fixed Price Swap
Stn. 2 Fixed Price Swap
Term
January 2018 - March 2018
January 2018 - March 2018
January 2018 - March 2018
January 2018 - March 2018
January 2018 - March 2018
January 2018 - March 2018
January 2018 - June 2018
January 2018 - December 2019
April 2018 - June 2019
April 2018 - September 2019
April 2018 - September 2019
Financial AECO Basis Differential Contracts
Options traded
AECO-Station 2 Basis Swap
Term
November 2018 - October 2020
AECO-Station 2 Basis Swap
November 2018 - October 2020
AECO-Station 2 Basis Swap
November 2018 - August 2021
AECO-Station 2 Basis Swap
November 2019 - October 2020
Financial WTI Crude Oil Contracts
Options traded
WTI Fixed Price Swap
WTI Fixed Price Swap
WTI Fixed Price Swap
WTI Fixed Price Swap
WTI Fixed Price Swap
Financial Propane Contracts
Options traded
Conway Fixed Price Swap
Conway Fixed Price Swap
Conway Fixed Price Swap
Term
January 2018 - December 2018
January 2018 - December 2018
January 2018 - December 2018
January 2018 - December 2019
January 2018 - December 2019
Term
January 2018 - December 2018
January 2018 - December 2018
January 2018 - December 2018
Volume
(GJ/d)
30,000
10,000
15,000
10,000
10,000
15,000
5,000
10,000
12,000
10,000
5,000
Price
(CDN$/GJ)
1.78
1.88
1.74
1.89
1.91
2.70
2.50
2.45
2.35
2.30
2.34
Volume
(GJ/d)
10,000
20,000
20,000
10,000
Price
(AECO less
CDN$/GJ)
0.32
0.32
0.29
0.33
Volume
(Bbl/d)
500
Price
(CDN$/Bbl)
65.15
250
250
500
500
70.15
71.05
70.20
70.20
Volume
(GAL/d)
8,400
10,500
8,400
Price
(CDN$/GAL)
0.90
0.88
1.00
In addition to the commodity risk management contracts discussed above, the Corporation has entered into physical
delivery sales contracts to manage commodity risk.
The Corporation has the following foreign exchange risk management contract in place as at December 31, 2017:
Reference
Currency
USD
Notional amount (USD 000s)
$1,000/month
Term
January 2018 - April 2018
Strike Rate
1.3538 CAD/USD
8
12
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
13
ROYALTIES
Royalty expense ($000s)
Per unit ($/Mcfe)
Royalties as a % of Revenue (%)
Three months ended
December 31,
Years ended
December 31,
2017
906
0.03
1.3
2016
1,382
0.07
2.1
2017
4,901
0.05
2.0
2016
2,672
0.05
2.2
For the year ended December 31, 2017 and December 31, 2016, royalties averaged 2.0% and 2.2% of revenue.
For the three months ended December 31, 2017, the lower royalty rate of 1.3% compared to 2.1% for the three
months ended December 31, 2016 can be attributed to reduced royalty rates on lower realized natural gas prices.
The majority of the Corporation’s properties are on the west side of the British Columbia royalty line and are eligible
to receive an average royalty credit of approximately $2.2 million per well. The remainder of the Corporation's
properties, on the east side of the British Columbia royalty line, are eligible to receive an average royalty credit of
approximately $0.8 million per well.
During 2018, the Corporation anticipates overall royalty rates to be approximately 2.0% to 2.5% of total revenues.
This estimate considers the combined impact of incremental sales volumes from newly drilled wells that will qualify
for royalty holidays, net of royalties paid on wells that have obtained the full benefit of provincial royalty incentives.
OPERATING EXPENSES
Operating expenses ($000s)
Per unit ($/Mcfe)
Three months ended
December 31,
Years ended
December 31,
2017
18,095
0.62
2016
12,035
0.59
2017
59,834
0.64
2016
34,535
0.68
Operating expenses increased by $0.03 per Mcfe or 5% in the fourth quarter of 2017 compared to the fourth quarter
of 2016 and decreased by $0.04 per Mcfe or 6% for the year ended December 31, 2017 compared to the year ended
December 31, 2016. Per unit operating expenses for the year ended December 31, 2017 have improved primarily
as a result of incremental production volumes positively impacting fixed cost components, as well as lower rental
expenses and consulting fees in 2017. Per unit operating expenses for the three months ended December 31, 2017
increased over 2016 due to voluntarily shut-ins of production, attributable to commodity pricing declines.
For 2018, the Corporation anticipates that average per unit operating expenses will be between $0.60 and $0.65
per Mcfe.
TRANSPORTATION COSTS
Transportation costs ($000s)
Per unit ($/Mcfe)
Three months ended
December 31,
2016
2017
7,653
13,646
0.38
0.47
Years ended
December 31,
2016
15,894
0.31
2017
39,197
0.42
Transportation costs for the three months and year ended December 31, 2017 increased by $0.09 per Mcfe or 24%
and $0.11 per Mcfe or 35%, respectively, compared to the three months and year ended December 31, 2016.
For both the three months and year ended December 31, 2017, the increased transportation costs per unit are the
result of an increase in transport tolls on third party pipelines, as well as higher liquids trucking costs compared to
the three months and year ended December 31, 2016, due to a 44% and 130% increase in liquids production
respectively.
9
12
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
13
During 2017, the Corporation signed various firm transportation agreements which facilitated its diversification into
the Dawn, Sumas, and AECO markets. On November 1, 2017, under a 10 year firm transportation agreement, the
Corporation began delivering 38 MMcf/d of natural gas to the Dawn market via the Long Term Fixed Price service,
with delivered volumes increasing to 88 MMcf/d by November 2019. On November 1, 2017, the Corporation began
delivering 6.4 MMcf/d of natural gas to Sumas via firm transportation on the Enbridge T-South system. As of February
1, 2018 the Corporation was delivering 174 MMcf/d to the AECO/NIT system with firm transportation through the
NGTL Towerbirch expansion.
For 2018, the Corporation expects average per unit transportation costs to be between $0.70 and $0.75 per Mcfe.
2018 per unit transportation costs are expected to be higher than 2017 as a result of increasing sales to more distant
sales points as part of our natural gas market diversification strategy, increased tolls on third party pipelines and an
anticipated increase in liquids production.
OPERATING NETBACKS
($/Mcfe)
Realized commodity price
Realized gain on risk management contracts
Royalties
Operating expenses
Transportation costs
Operating netbacks
Three months ended
December 31,
Years ended
December 31,
2017
2.34
0.83
(0.03)
(0.62)
(0.47)
2.05
2016
3.22
(0.09)
(0.07)
(0.59)
(0.38)
2.09
2017
2.65
0.47
(0.05)
(0.64)
(0.42)
2.01
2016
2.39
0.38
(0.05)
(0.68)
(0.31)
1.73
For the three months ended December 31, 2017, operating netbacks decreased by $0.04 per Mcfe or 2% compared
to the three months ended December 31, 2016. For the three months ended December 31, 2017, the decrease in
operating netbacks was the result of an 8% increase in combined per unit royalties, operating, and transportation
costs compared to the three months ended December 31, 2016, and lower realized commodity prices, offset by an
increase in realized gains on risk management contracts.
For the year ended December 31, 2017, operating netbacks increased by $0.28 per Mcfe or 16%, compared to the
year ended December 31, 2016. For the year ended December 31, 2017, the increase in operating netbacks is the
result of an 11% increase in realized commodity prices, a 24% increase in realized gains on risk management
contracts, offset by a 7% increase in combined per unit royalties, operating, and transportation costs compared to
the year ended December 31, 2016.
The Corporation’s operating netback for the three months and year ended December 31, 2017 was 88% and 76%
of revenue, respectively, compared to 65% and 72% of revenue for the three months and year ended December 31,
2016, respectively.
GENERAL AND ADMINISTRATIVE EXPENSES
($000s, except per Mcfe)
Gross expenses
Capitalized
Capital recoveries
Operating recoveries
Net expenses
Per unit ($/Mcfe)
Three months ended
December 31,
Years ended
December 31,
2017
7,749
(1,703)
(857)
(196)
4,993
0.17
2016
6,963
(2,646)
(668)
(118)
3,531
0.17
2017
26,134
(5,764)
(3,339)
(549)
16,482
0.18
2016
19,310
(5,937)
(2,343)
(464)
10,566
0.21
10
14
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
15
Net general and administrative (“G&A”) expenses for the three months ended December 31, 2017 were comparable
to the three months ended December 31, 2016. Annual net G&A decreased by $0.03 per Mcfe or 14%, compared
to the year ended December 31, 2016, due to higher production volumes.
The Corporation’s policy of allocating and capitalizing costs associated with new capital projects remained unchanged
for the year ended December 31, 2017. G&A capitalized and operating recoveries are in accordance with industry
practice.
For 2018, with increased production, the Corporation anticipates that per unit G&A expenses will average in the
range of $0.12 to $0.16 per Mcfe.
UGR ACQUISITION COSTS
For the year ended December 31, 2017, the Corporation expensed $5.5 million ($0.06 per Mcfe) in acquisition costs
related to the UGR acquisition. For the year ended December 31, 2017, UGR acquisition costs were $0.04 per basic
share.
FINANCE EXPENSE
($000s)
Finance lease expense
Interest expense
Accretion
Total
Per unit ($/Mcfe)
Three months ended
December 31,
2016
9,730
13,247
2017
Years ended
December 31,
2016
14,165
2017
44,157
5,837
877
19,961
0.69
2,691
158
12,579
0.62
15,640
1,794
61,591
0.66
8,055
550
22,770
0.45
Finance lease expense is a component of the capital fee paid on facilities treated as a capital lease, and varies with
production volumes processed. The capital fee includes finance lease expense and any amortization of the
outstanding finance lease obligation.
Interest expense includes interest on bank debt and standby charges on the Corporation’s syndicated credit facilities,
as well as interest on the senior notes and convertible debentures issued during the third quarter of 2017.
Per unit finance expense for the three months and year ended December 31, 2017 was $0.69 per Mcfe and $0.66
per Mcfe, respectively, compared to $0.62 per Mcfe and $0.45 per Mcfe for the three months and year ended
December 31, 2016. Interest expense increased for both the three months and year ended December 31, 2017 due
to larger available syndicated credit facilities on which standby fees are calculated, as well as additional interest
expense related to the senior notes and convertible debentures.
Accretion expense consists of accretion on the decommissioning obligation, senior notes and convertible debentures.
Accretion expense on the decommissioning obligation increased for the three months and year ended December 31,
2017, compared to the three months and year ended December 31, 2016 as a result of a higher decommissioning
liability balance and a higher risk free rate. At December 31, 2017, the risk free rate was 2.3% compared to 2.1% at
December 31, 2016. The Corporation has estimated the net present value of the decommissioning obligation based
on an undiscounted total future liability of $106.0 million at December 31, 2017, compared to $64.2 million at
December 31, 2016.
11
14
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
15
ADJUSTED FUNDS FLOW FROM OPERATIONS
($000s, except per Mcfe)
Petroleum and natural gas revenue
Royalties
Realized gain (loss) on risk management contracts
Operating expenses
Transportation costs
General and administrative expenses
Costs on acquisition of UGR
Finance lease expense
Interest expense
Adjusted funds flow from operations
Per unit ($/Mcfe)
SHARE-BASED COMPENSATION EXPENSE
($000s)
Gross expense
Capitalized
Share unit expense (recovery)
Total
Three months ended
December 31,
2016
Years ended
December 31,
2016
2017
65,155 249,186 121,580
(2,672)
(1,382)
(4,901)
19,912
(1,632)
44,002
(34,535)
(12,035)
(59,834)
(15,894)
(7,653)
(39,197)
(10,566)
(3,531)
(16,482)
— (5,497)
—
(14,165)
(9,730)
(44,157)
(8,055)
(2,691)
(15,640)
55,605
26,501 107,480
1.09
1.14
1.31
2017
67,798
(906)
24,156
(18,095)
(13,646)
(4,993)
—
(13,247)
(5,837)
35,230
1.21
Three months ended
December 31,
2016
711
(121)
2017
1,205
(586)
Years ended
December 31,
2017
2016
3,484
3,118
(620)
(913)
(399)
220
1,284
1,874
(1,724)
481
2,914
5,778
Gross share-based compensation expense was approximately $1.2 million for the three months ended December 31,
2017 and $0.7 million for the three months ended December 31, 2016. There were 600,000 stock options granted
during the three months ended December 31, 2017 at a weighted average exercise price of $3.52. For the three
months ended December 31, 2017, the weighted average fair value of stock options granted was $1.62 per stock
option.
Gross share-based compensation expense was approximately $3.1 million for the year ended December 31, 2017,
compared to $3.5 million for the year ended December 31, 2016. There were 3,376,650 stock options granted during
the year ended December 31, 2017 at a weighted average exercise price of $4.42. For the year ended December 31,
2017, the weighted average fair value of stock options granted was $2.00 per stock option.
Gross share-based compensation expense is a non-cash estimate of the cost of granting stock options to purchase
shares, calculated using the Black-Scholes model. The expense does not represent actual cash compensation
realized by the recipients of the stock options upon the exercise of these stock options.
Share Unit Plans
The Corporation has a deferred share unit ("DSU") plan, whereby DSUs are issued to members of the Board and
eligible executive officers. Each DSU is a notional unit equal in value to one common share in the capital of the
Corporation (“Common Share”), which entitles the holder to a cash payment upon redemption. DSUs vest upon grant
but can only be converted to cash upon the holder ceasing to be a director and/or executive officer of the Corporation.
The expense associated with the DSU plan is determined based on the 20-day volume weighted average price of
Common Shares at the grant date. The expense is recognized in the statement of operations immediately upon
grant, with a corresponding DSU liability recorded as a current liability in the statement of financial position. At period
end dates, the DSU liability is adjusted based on the 20-day volume weighted average price of Common Shares.
As at December 31, 2017, there were 690,104 DSUs outstanding under the plan.
12
16
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
17
The Corporation has a restricted share unit (“RSU”) plan, whereby RSUs are issued to eligible employees. Each
RSU is a notional unit equal in value to one Common Share, which entitles the holder to a cash payment upon
redemption. RSUs vest in three equal installments on the first, second, and third anniversaries of the grant date, at
which time the holder is eligible to receive a cash payment equal to the number of vested awards multiplied by the
fair market value. The expense associated with the RSU plan is determined based on the 20-day volume weighted
average price of Common Shares at the grant date. The expense is recognized in the statement of operations over
the vesting period, with a corresponding RSU liability recorded as a current liability in the statement of financial
position. At period end dates, the RSU liability is adjusted based on the 20-day volume weighted average price of
Common Shares. As at December 31, 2017, there were 222,630 RSUs outstanding under the plan.
The Corporation has a performance share unit (“PSU”) plan, whereby PSUs are issued to eligible executive officers.
Each PSU is a notional unit equal in value to one Common Share, which entitles the holder to a cash payment upon
redemption. PSUs vest upon the third anniversary of the grant date, at which time the holder is eligible to receive a
cash payment equal to the number of vested awards multiplied by the fair market value. The unit value is adjusted
for a performance multiplier which can range from 0 to 2 and is dependent on the performance of the Corporation
for a predefined period. The expense associated with the PSU plan is determined based on the 20-day weighted
average price of Common Shares at the grant date. The expense is recognized in the statement of operations over
the vesting period, with a corresponding PSU liability recorded as a current liability in the statement of financial
position. At period end dates, the PSU liability is adjusted based on the 20-day volume weighted average price of
Common Shares. As at December 31, 2017, there were 303,900 PSUs outstanding under the plan.
DEPLETION AND DEPRECIATION EXPENSE
Depletion and depreciation ($000s)
Per unit ($/Mcfe)
Three months ended
December 31,
2016
16,491
0.81
2017
24,921
0.86
Years ended
December 31,
2016
43,329
0.85
2017
83,887
0.89
Depletion and depreciation expense per unit for the three months and year ended December 31, 2017 of $0.86/Mcfe
and $0.89/Mcfe, respectively, were comparable to the three months and year ended December 31, 2016 depletion
and depreciation expense of $0.81/Mcfe and $0.85/Mcfe, respectively. The depletion calculation for the three months
ended December 31, 2017 included future development costs associated with the development of the Corporation's
proved plus probable reserves of $4.1 billion, compared to $2.9 billion for the three months ended December 31,
2016.
The Corporation’s exploration and evaluation (“E&E”) assets totaling $159.0 million as at December 31, 2017,
compared to $114.3 million as at December 31, 2016, were not subject to depletion. The increase in E&E assets
was the direct result of the undeveloped land acquired in the UGR acquisition. Substantially all of the E&E assets
relate to undeveloped land.
16
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
17
13
CAPITAL EXPENDITURES
($000s)
Drilling and completions
Facilities and equipment
Lease acquisitions and retention
Seismic
Property dispositions
Capitalized G&A
Exploration and development
Head office expenditures
Capital expenditures
Capital lease assets
Share-based compensation
Decommissioning costs1
UGR acquisition
Total
1. Subsequent to the date of acquisition, decommissioning liabilities acquired in the UGR acquisition were revalued, resulting in a $7.1 million increase to capital expenditures.
Three months ended
December 31,
2016
37,081
11,234
138
166
9
2,646
51,274
232
51,506
(4,140)
121
(2,214)
—
45,273
Years ended
December 31,
2016
152,894
43,767
614
716
(386)
5,937
203,542
849
204,391
360,860
620
7,929
—
573,800
2017
45,144
14,954
294
267
—
1,703
62,362
103
62,465
130,000
586
5,322
—
198,373
2017
240,640
49,613
1,095
4,143
19
5,764
301,274
1,340
302,614
130,000
913
14,973
207,491
655,991
During the three months and year ended December 31, 2017, the Corporation invested $62.4 million and $301.3
million, respectively, in exploration and development capital expenditures, compared to $51.3 million and $203.5
million, respectively, during the three months and year ended December 31, 2016.
Capital expenditures for the year ended December 31, 2017 included $240.6 million on drilling and completions
activity. The Corporation drilled 52 (52.0 net) and completed 51 (51.0 net) Montney natural gas wells during 2017
as part of the Corporation’s capital program. Facilities capital of $49.6 million for the year ended December 31, 2017
included equipping costs, pipeline construction costs and spending on processing facilities.
In 2018, the Corporation intends to drill 29 (29.0 net) and complete 31 (31.0 net) Montney horizontal natural gas
wells on its 100% working interest lands.
LIQUIDITY AND CAPITAL RESOURCES
As at December 31, 2017, the corporation had working capital of $33.0 million and net debt of $363.9 million.
Management anticipates that the Corporation will continue to have adequate liquidity to fund working capital
requirements and capital expenditures through a combination of cash flows, available credit facilities, senior notes
and convertible debentures. As a result of the current commodity pricing environment, uncertainty exists in the
commodity, credit and capital markets, which the Corporation continues to monitor in conjunction with its financing
alternatives.
SENIOR NOTES
On August 23, 2017, the Corporation issued $150.0 million of 8.5% senior unsecured notes (the "Notes") with a 5
year term by way of private placement. Proceeds net of discount and transaction costs of $8.9 million amounted to
$141.1 million. Interest is payable in equal quarterly installments in arrears. The Notes are fully and unconditionally
guaranteed as to the payment of principal and interest, on a senior unsecured basis by the Corporation. There are
no maintenance financial covenants.
The Notes are non-callable by the Corporation prior to the three year anniversary. If the Corporation chooses to
redeem the Notes prior to August 23, 2020, they will be subject to a make-whole premium equal to the Canada Yield
Price, plus accrued and unpaid interest. At any time on or after August 23, 2020, the Corporation can redeem all or
part of the Notes at the redemption prices set forth in the table below plus any accrued and unpaid interest.
14
18
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
19
Redemption Schedule
August 23, 2020 - August 22, 2021
August 23, 2021 - February 22, 2022
February 23, 2022 - August 23, 2022
Percentage
104.250%
102.125%
100.000%
If a change of control event occurs at any time before maturity, the Corporation must offer to repurchase the Notes
at a price according to the redemption schedule above.
CONVERTIBLE DEBENTURES
On August 23, 2017, the Corporation issued $50.0 million of convertible unsecured subordinated debentures (the
"Debentures") for net proceeds of $47.7 million. The Debentures mature on August 23, 2021 and bear interest at
6.5% per annum payable quarterly commencing November 23, 2017. At the holder's option, the Debentures may be
converted into common shares of the Corporation at any time prior to the close of business on the date of maturity
at a conversion price of $5.60 per share (the "conversion price").
The Debentures are non-redeemable by the Corporation between August 23, 2017 and February 22, 2020 other
than pursuant to the 90% redemption right (see Change of Control below). The Debentures are redeemable by the
Corporation between February 23, 2020 and August 23, 2021 at a redemption price equal to principal amount plus
interest. Redemption may be satisfied in common shares if the 30-day volume weighted average price ('VWAP") on
notice date and the closing price immediately prior to notice date are both greater than 140% of the conversion price.
On maturity, the Corporation may satisfy its obligation to Debenture holders by issuing common shares if the
Corporation's market capitalization exceeds $750 million. The number of common shares issued is calculated based
on 95% of the lesser of the 30-day VWAP and the 2-day VWAP on the date of maturity.
Upon occurrence of a change of control event, the Corporation must offer to repurchase the Debentures at a price
according to the schedule below. If 90% or more of the principal amount accept the offer, the Corporation shall have
the right to repurchase 100% of the Debentures outstanding.
Redemption Schedule
August 23, 2017 - August 22, 2018
August 23, 2018 - February 22, 2020
February 23, 2020 - August 23, 2021
BANK DEBT
Percentage of
Principal
110.000%
105.000%
100.000%
At December 31, 2017, the Corporation’s syndicated credit facilities consisted of available credit facilities of $450
million. The available facilities are provided by a syndicate of financial institutions, and include a $400 million
extendable revolving facility and a $50 million operating facility. The facilities revolve for a 2-year period, which is
extendable annually, subject to syndicate approval. The facilities are subject to semi-annual review and re-
determination of borrowing base by April 30 and October 31 of each year, or in the circumstance of a material adverse
change. Any re-determination of the borrowing base is effective immediately, and if the borrowing base is reduced,
the Corporation has 60 days to repay any shortfall.
As at December 31, 2017, Painted Pony had $160 million in bankers’ acceptances with an effective interest rate of
3.65% per annum. In addition, as at December 31, 2017, the Corporation had outstanding letters of credit totaling
$21.5 million and US$15.0 million, which reduce the credit available on the syndicated facilities. At December 31,
2016, the Corporation had an outstanding letter of credit of $14.9 million.
The credit facilities bear interest on a matrix system that ranges from the bank’s prime rate plus 1.0% to the bank’s
prime rate plus 3.25% per annum depending on the Corporation’s senior debt to quarterly annualized EBITDA ratio
as defined by the lenders, ranging from less than 1.00:1 to 3.00:1. The credit facilities provide that advances may
15
18
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
19
be made by way of prime rate loans, U.S. Base Rate loans, London InterBank Offered Rate loans, bankers’
acceptances, letters of credit or letters of guarantee. A standby fee of 0.5% to 0.8125% per annum is charged on
the undrawn portion of the credit facilities, also calculated depending on the Corporation’s senior debt to quarterly
annualized EBITDA ratio, as defined by the lenders.
Security over all of the Corporation’s assets is provided by a floating charge demand debenture in the aggregate
amount of $1.0 billion. The Corporation has provided a negative pledge and an undertaking to provide fixed charges
over its petroleum and natural gas reserves in certain circumstances. The Corporation's syndicated credit facilities
include financial covenants as follows: senior debt to EBITDA ratio of not greater than 3.00:1 on a trailing four fiscal
quarter basis, and total debt to EBITDA ratio of not greater than 4.25:1 on a trailing four fiscal quarter basis until Q2
2018, thereafter of not greater than 4.00:1 on a trailing four fiscal quarter basis. At December 31, 2017 the senior
debt to EBITDA ratio was 1.77:1.00, and the total debt to EBITDA ratio was 3.28:1.00.The Corporation is in compliance
with all covenants as at December 31, 2017.
ALTAGAS STRATEGIC ALLIANCE
The Corporation is party to a series of agreements (collectively the “Strategic Alliance”) with AltaGas Ltd. (“AltaGas”)
relating to the development of processing infrastructure and marketing services for natural gas and NGLs.
Under the Strategic Alliance, AltaGas committed to building gas processing facilities including a 198 MMcf/d shallow
cut gas processing facility at the Townsend property and related pipeline infrastructure, which commenced commercial
operations in 2016. Painted Pony does not acquire any legal right, title, or interest in the Townsend Facility or pipeline.
All construction costs were borne by AltaGas. The Corporation has the right to a minimum of 198 MMcf/d of firm
capacity, in respect of which there is a take or pay obligation on production volumes delivered to the facility of 180
MMcf/d.
During the second quarter of 2017, Painted Pony entered into an agreement with AltaGas in respect of a Townsend
Phase 2 expansion. The Townsend Phase 2 expansion consists of a 99 MMcf/d gas processing train located on the
existing Townsend site adjacent to, and sharing joint equipment with the original Townsend Facility. The Corporation
has the right to the full 99 MMcf/d of firm capacity at Townsend Phase 2, since commencement of commercial
operation in the fourth quarter of 2017, in respect of which there is a take or pay obligation on production volumes
delivered to the facility of 90 MMcf/d commencing in the first quarter of 2018.
The Townsend Facility, related pipeline infrastructure and Phase 2 expansion have been recorded as a finance lease.
Painted Pony has recorded the asset, representing the total estimated construction cost of the Townsend Facility of
$490.9 million, with a corresponding obligation on the statement of financial position. Over the course of the 20-year
lease, there will be a capital fee paid to AltaGas, which will include finance costs and the amortization of the obligation.
The associated processing fee will be recorded in operating expenses.
Total expected payments based on annual take or pay volumes, including both the principal and financing components,
are reflected in the table below.
($000s)
Processing
Transportation
Total
Principal
Within 1 year
52,328
9,880
62,208
3,282
After 1 year but not
more than five years
269,998
53,114
323,112
64,981
More than five
years
579,843
182,355
762,198
422,597
Total
902,169
245,349
1,147,518
490,860
In conjunction with the Phase 2 expansion, AltaGas commissioned a fractionation facility and railway terminal. All
NGL Mix produced at the expanded AltaGas Townsend Facility is now pipelined directly to the AltaGas Fractionation
Facility, while the stabilized condensate flows directly to the AltaGas Rail Terminal.
16
20
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
21
COMMITMENTS
The following is a summary of the estimated costs required to fulfill Painted Pony’s remaining contractual commitments
as at December 31, 2017.
($000s)
Transportation and processing
Interest on senior notes
Interest on convertible debentures
Office leases and other
Total commitments
2018
77,704
2019
90,093
2020
99,775
2021
98,020
2022 Thereafter
Total
97,438 1,030,077 1,493,107
14,242
3,250
1,740
67,595
14,765
12,188
2,438
3,181
101
96,936 108,958 117,755 115,324 107,021 1,030,077 1,576,071
14,613
3,250
117
14,399
3,250
1,216
9,576
—
7
—
—
—
Transportation commitments include contracts to transport natural gas and NGLs through third-party owned pipeline
systems in Canada. Processing commitments include contracts to process natural gas through third-party owned
gas processing facilities in British Columbia. Interest on senior notes includes quarterly interest on senior notes.
Interest on convertible debentures includes quarterly interest on convertible debentures. Office leases include the
Corporation’s contractual obligations for office space.
The Corporation has certain lease arrangements that are reflected in the commitments table above, which were
entered into in the normal course of operations. All leases, other than the Townsend Facility finance lease, have
been treated as operating leases whereby the lease payments are included in operating expenses or general and
administrative expenses depending on the nature of the lease.
OFF BALANCE SHEET ARRANGEMENTS
No off balance sheet arrangements existed as at December 31, 2017 or December 31, 2016, except those noted
within.
SHARE CAPITAL
The Corporation has an unlimited number of Common Shares and an unlimited number of preferred shares ("Preferred
Shares") authorized for issuance. As at December 31, 2017 and March 7, 2018, there were 160,995,692 Common
Shares issued and outstanding, respectively. At December 31, 2017 and March 7, 2018, there were no Preferred
Shares issued and outstanding.
The Corporation has a stock option plan, pursuant to which options to purchase Common Shares are granted to
officers and employees of the Corporation. Stock options are granted at the volume weighted average trading price
of the Common Shares for the five trading days immediately preceding the date of grant, and have a five-year term.
Stock options granted vest as to one-third on each of the first, second and third anniversaries of the grant date. As
at December 31, 2017, an aggregate of 10,298,367 stock options were issued and outstanding at a weighted-average
price of $6.01 per stock option. As at March 7, 2018, an aggregate of 11,836,192 stock options were issued and
outstanding at a weighted-average price of $5.33 per stock option.
INCOME TAXES
As at December 31, 2017, the Corporation had a $7.8 million deferred tax liability. This compares to a $32.6 million
deferred tax asset at December 31, 2016. The deferred tax expense was $45.4 million during the year ended
December 31, 2017, compared to a deferred income tax recovery of $17.9 million during the year ended December 31,
2016.
The Corporation expects that future taxable income will be available to utilize accumulated tax pools. Painted Pony’s
estimated tax pools at December 31, 2017 were $1.4 billion.
DIVIDENDS
The Corporation has not declared or paid any dividends and does not intend to do so in the near future.
17
20
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
21
PERFORMANCE COMPARED TO EXPECTATIONS
Readers are reminded that forward-looking statements in this MD&A are subject to significant risks and uncertainties,
many of which are beyond Painted Pony’s control and are based on a number of material factors and assumptions,
some or all of which may prove to be incorrect. See "Advisories - Forward-looking Statements" in the MD&A for
further discussion of forward looking statements, risks and uncertainties. A comparison of actual performance to the
previously announced expectations of the Corporation is as follows:
• For the fourth quarter of 2017, the Corporation expected to receive a realized natural gas price at a premium
to the benchmark Westcoast Station 2 price and comparable to the AECO (5A) benchmark price. The actual
weighted average price received during the fourth quarter of 2017 represented a 196% premium to the
Westcoast Station 2 price and a 2% discount to the AECO 5A daily spot price.
• Painted Pony’s royalty rate for the fourth quarter of 2017 was expected to be approximately 2.5% of total
revenues. The actual royalty rate for the fourth quarter of 2017 was 1.3% of total revenues. Royalty rates
were lower than expectation due to pricing declines during the fourth quarter of 2017.
• Operating expenses for the fourth quarter of 2017 were expected to be between $0.60 and $0.65 per Mcfe.
Actual operating expenses for the fourth quarter were $0.62 per Mcfe.
• Transportation expenses for the fourth quarter of 2017 were expected to be between $0.35 and $0.40
per Mcfe. Actual transportation expenses for the quarter were $0.47 per Mcfe due to an increase in transport
tolls on third party pipelines, as well as higher liquids trucking costs.
• Net G&A expenses for the fourth quarter of 2017 were expected to be $0.10 to $0.15 per Mcfe. Actual net
G&A for the fourth quarter were $0.17 per Mcfe. G&A expenses were higher than expectation due to increased
professional fees.
CRITICAL ACCOUNTING JUDGMENTS AND ESTIMATES
The preparation of financial statements requires management to make judgments, estimates and assumptions that
affect the application of IFRS accounting policies, reported amounts of assets and liabilities, and income and
expenses. Accordingly, actual results may differ from these estimates. Estimates and underlying assumptions are
reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates
are revised and in any future periods affected.
Critical Accounting Judgments
The following are critical judgments that management has made in the process of applying accounting policies and
that have the most significant effect on the amounts recognized in the consolidated financial statements.
Cash-Generating Units
The Corporation’s assets are aggregated into cash-generating units (“CGU” or “CGUs”) for the purpose of
assessing impairment. CGUs are based on an assessment of the unit’s ability to generate independent
cash inflows. The determination of these CGUs was based on management’s judgment in regard to shared
infrastructure, geographical proximity, petroleum type and exposure to market risk and materiality. By their
nature, these assumptions are subject to management’s judgment and may impact the carrying value of the
Corporation’s net assets in future periods.
Impairment Indicators
Judgments are required to assess when impairment indicators exist and impairment testing is required. The
Corporation is required to consider information from both external sources (such as negative downturn in
commodity prices, significant adverse changes in the technological, market, economic or legal environment
in which the entity operates) and internal sources (such as downward revisions in reserves, significant
adverse effect on the financial and operational performance of a CGU, evidence of obsolescence or physical
damage to the asset). In determining the recoverable amount of assets, in the absence of quoted market
prices, impairment tests are based on estimates of reserves, production rates, future petroleum and natural
gas prices, future costs, discount rates, market value of land and other relevant assumptions.
The application of the Corporation’s accounting policy for exploration and evaluation (“E&E”) assets requires
management to make certain judgments as to future events and circumstances as to whether economic
quantities of reserves have been found.
18
22
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
23
Deferred Taxes
In determining its deferred tax provisions, the Corporation must apply judgment when interpreting and
applying tax laws and regulations. The determination of the appropriate rules may be uncertain for many
periods. The final outcome could result in amounts different from those initially recorded and could impact
tax expense in the periods where a determination is made. Judgments are also made by management to
determine the likelihood of whether deferred tax assets at the end of the reporting period will be realized
from future taxable income.
Critical Accounting Estimates
The following are key estimates made by management affecting the measurement of balances and transactions in
these consolidated financial statements.
Impact of Reserves
Estimation of recoverable quantities of proved and probable reserves includes estimates regarding future
commodity prices, exchange rates, discount rates and production and transportation costs for future cash
flows as well as the interpretation of complex geological and geophysical models and data. Changes in
expected future cash flows in reported reserves can affect the impairment of assets, the decommissioning
obligation, the economic feasibility of E&E assets and the amounts reported for depletion and depreciation
of property, plant and equipment (“PP&E”), and the recognition of deferred tax assets. These reserve
estimates are prepared in accordance with the Canadian Oil and Gas Evaluation Handbook and are verified
by independent qualified reserve evaluators, who work with information provided by the Corporation to
establish reserve determinations in accordance with National Instrument 51-101 - Standards of Disclosure
for Oil and Gas Activities (“NI 51-101”).
In a business combination, management makes estimates of the fair value of assets acquired and liabilities
assumed which includes assessing the value of petroleum and natural gas properties based upon the
estimation of recoverable quantities of proved and probable reserves being acquired.
Share-Based Compensation
All equity-settled, share-based awards issued by the Corporation are fair valued using the Black-Scholes
option-pricing model. In assessing the fair value of equity-based compensation, estimates have to be made
regarding the expected volatility in share price, option life, dividend yield, risk-free rate and estimated
forfeitures at the initial grant date.
Derivative Financial Instruments
Painted Pony records risk management contracts at fair value with changes in fair value recognized in the
consolidated statements of operations. The Corporation’s estimate of the fair value is determined using
observable market data and external counterparty information, including estimated forward prices and
volatility in those prices.
Decommissioning Obligation
The Corporation estimates future remediation costs of production facilities, wells and pipelines at different
stages of development and construction of assets or facilities. In most instances, removal of assets occurs
many years into the future. This requires estimates regarding abandonment date, future environmental and
regulatory legislation, the extent of reclamation activities, the engineering methodology for estimating cost,
future removal technologies in determining the removal cost and liability-specific discount rates to determine
the present value of these cash flows.
Deferred Taxes
Tax provisions are based on enacted or substantively enacted laws. Changes in those laws could affect
amounts recognized in income or loss both in the period of change, which would include any impact on
cumulative provisions, and in future periods.
Deferred tax assets are recognized only to the extent it is considered probable that those assets will be
recoverable. This involves an assessment of when those deferred tax assets are likely to reverse and a
judgment as to whether or not there will be sufficient taxable income available to offset the tax assets when
they do reverse. This requires assumptions regarding future profitability and is therefore inherently uncertain.
Estimates of future taxable income are based on forecasted cash flows from operations.
19
22
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
23
FUTURE ACCOUNTING PRONOUNCEMENTS
A number of new accounting standards, amendments to accounting standards and interpretations are effective for
annual periods beginning on or after January 1, 2018 and have not yet been applied in preparing the consolidated
financial statements for the year ended December 31, 2017. The standards applicable to the Corporation are as
follows and will be adopted on their respective effective dates:
Financial Instruments
In July 2014, the IASB issued the final version of IFRS 9 “Financial Instruments”, which replaces IAS 39 “Financial
Instruments: Recognition and Measurement”. The standard will come into effect for annual periods beginning on or
after January 1, 2018 with earlier adoption permitted.
IFRS 9 introduces a single approach to determine whether a financial asset is measured at amortized cost or fair
value and replaces the multiple rules in IAS 39. The approach is based on how an entity manages its financial
instruments in the context of its business model and the contractual cash flow characteristics of the financial assets.
For financial liabilities, IFRS 9 retains most of the requirements of IAS 39; however, where the fair value option is
applied to financial liabilities, any change in fair value resulting from an entity’s own credit risk is recorded in OCI
rather than the statement of operations, unless this creates an accounting mismatch. Based on its preliminary
assessment, the Corporation does not anticipate these changes to have a material impact on its consolidated financial
statements.
In addition, IFRS 9 introduces a new expected credit loss model for calculating impairment of financial assets,
replacing the incurred loss impairment model required by IAS 39. The new model will result in more timely recognition
of expected credit losses. Painted Pony does not anticipate the new impairment model to have a material impact on
the consolidated financial statements.
IFRS 9 also contains a new model to be applied for hedge accounting, aligning hedge accounting more closely with
risk management. The Corporation does not currently apply hedge accounting to its risk management contracts and
does not currently intend to apply hedge accounting to any of its existing risk management contracts on adoption of
IFRS 9.
Revenue Recognition
As of January 1, 2018, the Corporation has adopted IFRS 15 “Revenue from Contracts with Customers”, which
replaces IAS 18 “Revenue”. The standard provides a single, principles based 5 step model to be applied to all
contracts with customers. The standard requires an entity to recognize revenue to reflect the transfer of goods and
services for the amount it expects to receive, when control is transferred to the purchaser. Disclosure requirements
have also been expanded.
The standard has been adopted using a modified retrospective approach effective January 1, 2018. The Corporation
has reviewed its revenue streams and underlying contracts with customers and has determined that there will not
be a material impact on its earnings. Additional disclosures will be implemented.
Leases
In January 2016, the IAS issued IFRS 16 “Leases”, which replaces IAS 17 “Leases”, and provides that a single
recognition and measurement model for leases would apply, with required recognition of assets and liabilities for
most leases. For lessees, IFRS 16 removes the classification of leases as either operating or finance leases, effectively
treating all leases as finance leases. Certain short-term leases (less than 12 months) and leases of low-value assets
are exempt from the requirements, and may continue to be treated as operating leases.
IFRS 16 is effective for years beginning on or after January 1, 2019, with early adoption permitted if IFRS 15 “Revenue
from Contracts with Customers” has been adopted. The standard may be applied retrospectively or using a modified
retrospective approach. It is anticipated that the adoption of IFRS 16 will have an impact on the Corporation’s
consolidated statement of financial position.
20
24
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
25
BUSINESS RISKS
Painted Pony’s production and exploration and development activities are concentrated in western Canada, where
activity is highly competitive and includes a variety of companies ranging from smaller junior producers to the much
larger integrated producers. Painted Pony is subject to various types of business risks and uncertainties, including
but not limited to:
volatility of natural gas and crude oil prices;
availability of qualified personnel and drilling equipment;
finding and developing petroleum and natural gas reserves at economic costs;
production of petroleum and natural gas in commercial quantities; and
•
•
•
•
• marketability of petroleum and natural gas production.
In order to reduce exploration risk, the Corporation strives to employ highly qualified and motivated professional
employees and consultants with a demonstrated ability to generate quality proprietary geological and geophysical
prospects. To help maximize drilling success, Painted Pony combines exploration in areas that afford multi-zone
prospect potential, targeting a range of low to moderate risk prospects with minimal exposure to select high-risk
plays with high-reward opportunities. Painted Pony also explores in areas where the Corporation’s officers and
employees have significant experience.
The Corporation mitigates its risks related to producing hydrocarbons through the utilization of the most appropriate
technology and information systems. Painted Pony seeks operational control of its projects, where feasible.
Oil and gas exploration, development and production can involve environmental risks such as pollution of the
environment and destruction of natural habitat, as well as safety risks such as personal injury. In order to mitigate
such risks, Painted Pony conducts its operations with high standards and follows safety procedures intended to
reduce the potential for personal injury to employees, contractors and the public at large. The Corporation maintains
insurance coverage to address significant business risks, at market rates and within defined limits and deductibles.
The amount and terms of this insurance are reviewed on an ongoing basis and adjusted as necessary to reflect
changing corporate requirements, as well as industry standards and government regulations. Painted Pony may
periodically use financial or physical delivery hedges to reduce its exposure against the potential adverse impact of
commodity price volatility, as governed by formal policies approved by senior management, subject to controls
established by the Board.
The Corporation uses financial derivatives and physical delivery sales contracts to mitigate some of the exposure
to commodity price risk, and provide a level of stability to operating cash flows which enables the Corporation to fund
its capital development program.
Additional information about the Corporation’s business risks is outlined in the advisories section of this MD&A and
is available in Painted Pony’s AIF for the year ended December 31, 2017 that is filed on SEDAR at www.sedar.com.
LEGAL, ENVIRONMENTAL, REMEDIATION AND OTHER CONTINGENT MATTERS
The Corporation reviews legal, environmental, remediation and other contingent matters to determine whether a
loss is probable based on judgment and interpretation of laws and regulations, and to determine whether the loss
can reasonably be estimated. When the loss is determined, it is charged to income. The Corporation’s management
monitors known and potential contingent matters and makes appropriate provisions by charges to income when
warranted by the circumstances.
The Corporation may from time to time be involved in legal claims or litigation arising in the normal course of business.
The outcome of legal claims or litigation is uncertain and there can be no assurance that such legal claims or litigation
will be resolved in the Corporation’s favor. Other than disclosed herein, the Corporation does not currently believe
that the outcome of adverse decisions in any pending or threatened legal claims or litigation, or any amount which
it may be required to pay, would have a material adverse impact on its financial position or results of operations.
Aboriginal peoples have claimed aboriginal title and rights to portions of western Canada, including northeast British
Columbia. On May 31, 2017, the British Columbia Supreme Court denied an injunction application brought by the
Blueberry River First Nation ("BRFN") which sought to restrain the Province of British Columbia from, among other
21
24
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
25
things, permitting new oil and gas activities within a portion of northeast British Columbia, where a substantial portion
of the Corporation’s land is situated. Had the injunction application been successful, it would likely have had an
adverse impact on the Corporation, its operations and production. The interlocutory injunction was part of an
underlying claim, by the BRFN against the Province of British Columbia, filed on March 3, 2015, which seeks relief
for alleged breaches of treaty rights in northeast British Columbia. The underlying claim is scheduled to be heard by
the British Columbia Supreme Court in the spring 2018. The Corporation was not a party to the interlocutory injunction
and it is not party to the underlying claim.
DISCLOSURE CONTROLS & PROCEDURES AND INTERNAL CONTROL OVER FINANCIAL REPORTING
The Corporation’s Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) have designed, or caused to
be designed under their supervision, disclosure controls and procedures (“DC&P”), as defined in National Instrument
52-109 - Certification of Disclosure in Issuer’s Annual and Interim Filings (“NI 52-109”) to provide reasonable
assurance that: (i) material information relating to the Corporation is made known to the Corporation’s CEO and CFO
by others, particularly during the period in which the annual and interim filings are being prepared; and (ii) information
required to be disclosed by the Corporation in its annual filings, interim filings or other reports filed or submitted by
it under securities legislation is recorded, processed, summarized and reported within the time period specified in
securities legislation. As at December 31, 2017, the CEO and CFO evaluated the design and operation of the
Corporation’s DC&P. Based on that evaluation, the CEO and CFO concluded that the Corporation’s DC&P was
effective as at December 31, 2017.
The Corporation’s CEO and CFO have designed, or caused to be designed under their supervision, internal controls
over financial reporting (“ICFR”), as defined in NI 52-109, to provide reasonable assurance regarding the reliability
of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. The
Corporation has established and maintains ICFR using the criteria that were set forth by the Committee of Sponsoring
Organizations of the Treadway Commission in Internal Control - Integrated Framework (2013). As at December 31,
2017, the CEO and CFO evaluated the design and operating effectiveness of the Corporation’s ICFR. Based on that
evaluation, the CEO and CFO concluded that the Corporation’s ICFR was effective as at December 31, 2017.
No material changes in the Corporation’s ICFR were identified during the period beginning on October 1, 2017 and
ended on December 31, 2017 that have materially affected, or are reasonably likely to materially affect, the
Corporation’s ICFR. It should be noted that a control system, including the Corporation’s disclosure and internal
controls and procedures, no matter how well conceived, can provide only reasonable, but not absolute assurance
that the objectives of the control system will be met and it should not be expected that the disclosure and internal
controls will prevent all errors or fraud.
22
26
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
27
SELECTED CONSOLIDATED QUARTERLY INFORMATION
The following tables set forth selected consolidated financial information of the Corporation for the eight most recently
completed quarters ending at the fourth quarter of 2017.
Quarter ended ($000s, except where noted)
Petroleum and natural gas revenue
Cash flow from operating activities
Per share - basic
Per share - diluted
Adjusted funds flow from operations
Per share - basic
Per share - diluted
Net income
Per share - basic
Per share - diluted
Capital expenditures
Working capital (deficiency)
Bank debt
Senior notes
Convertible debentures - liability
Net debt
Total assets
Decommissioning obligation
Average daily production volumes (boe/d)
Average daily production volumes (MMcfe/d)
Realized commodity prices
Natural gas ($/Mcf)
NGLs ($/bbl)
Total ($/Mcfe)
Operating netbacks ($/Mcfe)
Quarter ended ($000s, except where noted)
Petroleum and natural gas revenue
Cash flow from operating activities
Per share - basic
Per share - diluted
Adjusted funds flow from operations
Per share - basic
Per share - diluted
Net income (loss)
Per share - basic
Per share - diluted
Capital expenditures
Working capital (deficiency)
Bank debt
Net debt
Total assets
Decommissioning obligation
Average daily production volumes (boe/d)
Average daily production volumes (MMcfe/d)
Realized commodity prices
Natural gas ($/Mcf)
NGLs ($/bbl)
Total ($/Mcfe)
Operating netbacks ($/Mcfe)
Dec 31, 2017 Sept 30, 2017
50,016
29,609
0.18
0.18
29,462
0.18
0.18
14,592
0.09
0.09
85,592
(21,486)
93,759
141,260
44,597
336,405
1,809,283
41,255
42,353
254.1
67,798
27,417
0.17
0.16
35,230
0.22
0.21
37,067
0.23
0.22
62,465
33,025
149,228
141,613
44,887
363,884
2,031,643
46,811
52,544
315.3
Jun 30, 2017 Mar 31, 2017
64,948
31,661
0.32
0.31
24,799
0.25
0.25
56,888
0.57
0.56
96,678
(74,225)
232,649
—
—
299,791
1,406,214
30,431
35,878
215.3
66,424
18,230
0.13
0.13
17,989
0.13
0.13
13,829
0.10
0.10
57,879
(30,794)
235,547
—
—
283,538
1,742,761
44,517
40,574
243.4
1.66
56.81
2.34
2.05
1.59
45.70
2.14
2.12
2.64
47.04
3.00
1.81
2.87
50.30
3.35
2.08
Dec 31, 2016 Sept 30, 2016
27,987
10,325
0.10
0.10
12,639
0.13
0.12
11,614
0.12
0.11
50,471
(36,626)
172,054
202,494
1,290,228
32,015
22,741
136.4
65,155
21,859
0.22
0.21
26,501
0.26
0.26
(27,761)
(0.28)
(0.28)
51,506
(73,647)
200,836
228,463
1,336,955
29,857
36,695
220.2
Jun 30, 2016 Mar 31, 2016
16,575
7,202
0.07
0.07
7,557
0.08
0.08
(2,151)
(0.02)
(0.02)
67,076
(26,016)
87,559
137,239
857,942
25,738
16,601
99.6
11,863
5,272
0.05
0.05
8,908
0.09
0.09
(33,559)
(0.34)
(0.34)
35,338
(36,677)
136,897
164,493
876,295
27,321
16,634
99.8
2.78
46.62
3.22
2.09
1.97
41.67
2.23
1.74
0.94
41.73
1.31
1.44
1.60
36.26
1.83
1.21
23
26
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
27
SELECTED CONSOLIDATED ANNUAL INFORMATION
The following tables set forth selected consolidated annual financial information of the Corporation for the three most
recently completed years ending December 31, 2017.
Year ended
($000s, except where noted)
Petroleum and natural gas revenue
Cash flow from operating activities
Per share - basic
Per share - diluted
Dec 31,
2017
249,186
106,917
0.76
0.74
Dec 31,
2016
121,580
44,658
0.45
0.45
Dec 31,
2015
81,583
31,705
0.32
0.32
Adjusted funds flow from operations
107,480
55,605
28,466
Per share - basic
Per share - diluted
Net income (loss)
Per share - basic
Per share - diluted
Capital expenditures
Working capital (deficiency)
Bank debt
Senior notes
Convertible debentures - liability
Net debt
Total assets
Decommissioning obligation
Average daily production volumes (boe/d)
Average daily production volumes (MMcfe/d)
0.76
0.75
0.56
0.56
122,376
(51,857)
0.87
0.85
302,614
33,025
149,228
141,613
44,887
363,884
(0.52)
(0.52)
204,391
(73,647)
200,836
—
—
228,463
2,031,643
1,336,955
46,811
42,882
257.3
29,857
23,204
139.2
0.29
0.29
(5,210)
(0.05)
(0.05)
106,654
(4,629)
63,626
—
—
77,361
781,574
21,480
15,604
93.6
Significant factors and trends that have affected the Corporation’s results during the above annual and quarterly
periods include:
• Petroleum and natural gas revenues are impacted by both fluctuating commodity prices and production
volumes. The Corporation’s successful capital program and commencement of commercial operations at
the Townsend Facility have generated incremental production volumes, offset by shut-in production volumes
during low pricing environments. The commodity prices realized by the Corporation have approximated the
AECO daily spot gas prices and Edmonton par light oil prices with periodic widening of differentials throughout
the above periods. The reference price fluctuations reflect changes in supply and demand by commodity,
both internationally and domestically.
• Adjusted funds flow from operations reflects the impact of fluctuating commodity prices on a growing
production base. Operating and transportation cost variations track seasonal weather-related issues
combined with fixed commitments. Natural gas and crude oil prices declined through the first half of 2016.
Prices started to recover in the second half of 2016, and into the first and second quarter of 2017, however
declined through the third and fourth quarter of 2017.
• Royalties vary due to commodity prices, production levels and the status of provincial royalty incentive
programs. As the production base matures, incremental royalties occur on wells as the maximum volumes
provided for under provincial incentive programs are attained.
• Net income (loss) and comprehensive income (loss) throughout the periods was primarily influenced by
unrealized gains or losses on risk management contracts and acquisition costs.
• Fluctuations in capital expenditures have reflected both available capital resources and capital spending
restraints during weaker commodity price cycles.
• As the Corporation’s focus has shifted to development and production, the Corporation has begun utilizing
bank debt and has issued convertible debentures and senior notes to assist with the capital program and
debt repayment. As the Corporation proceeds with its growth plans, bank debt amounted to $149.2 million
24
28
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
29
as at December 31, 2017, the carrying value of senior notes was $141.6 million and the carrying value of
the liability portion of the convertible debentures was $44.9 million.
• Total assets and non-current liabilities have increased as the Corporation’s capital program has been
executed.
ADVISORIES
Forward-looking Statements
Certain statements in this MD&A constitute forward-looking statements and forward-looking information (collectively,
the “forward-looking statements”) within the meaning of applicable Canadian securities laws. Such forward-looking
statements relate to future events, including expectations of future production, components of cash flow and net
income, expected future events, including with respect to the Corporation’s well program, contractual commitments,
capital expenditures, dividend policy and credit facility, and/or financial results that are forward-looking in nature and
subject to substantial risks and uncertainties. All statements other than statements of historical fact contained in this
MD&A may be forward-looking statements. Such statements and information may be identified by words such as
“anticipate”, “will”, “intend”, “could”, “should”, “may”, “might”, “expect”, “forecast”, “plan”, “potential”, “project”,
“assume”, “contemplate”, “believe”, “budget”, “shall”, “continue”, “milestone”, “target”, “vision”, “forward looking to”,
and similar terms or the negatives thereof or other comparable terminology. The forward-looking statements contained
in this MD&A involve known and unknown risks, uncertainties and other factors that are beyond the Corporation’s
control, which may cause actual results or events to differ materially from those anticipated in such forward-looking
statements.
The forward-looking statements contained in this MD&A represent management’s reasonable projections,
expectations and estimates as of the date of this document; however, undue reliance should not be placed upon
them as they are derived from numerous assumptions, certain or all of which may prove to be incorrect. These
assumptions are subject to known and unknown risks and uncertainties, including the business risks discussed in
this MD&A and the risks discussed in the Corporation’s AIF for the year ended December 31, 2017, many of which
are beyond Painted Pony’s control and which may cause actual performance and financial results to differ materially
from any projections of future performance or results expressed or implied by such forward-looking statements. In
addition, forward-looking statements may include statements or information attributable to third-party industry
sources. Additionally, there can be no assurance that the plans, intentions or expectations upon which such forward-
looking statements are based will occur.
In particular, and without limitation, this MD&A contains forward-looking statements pertaining to the following:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
the expectation that efficiencies associated with the Townsend Phase 2 expansion will reduce the fixed
capital fee on a per MCF basis paid by the Corporation by approximately 20% after commencement of the
Townsend Phase 2 expansion take or pay;
the Corporation receiving a natural gas price that represents a premium to the Westcoast Station 2 price
and comparable to the AECO (5A) benchmark price;
expectations with respect to average price estimates for 2018;
the expectation that exposure to Station 2 pricing is expected to average below 15% in 2018;
the expectation that overall royalties for 2018 will be approximately 2.0% to 2.5% of total revenues;
the expectation that average per unit operating expenses for 2018 will be between $0.60 and $0.65 per
Mcfe, assuming normal seasonal weather conditions;
the expectation that average per unit transportation costs for 2018 will be between $0.70 and $0.75 per
Mcfe;
the expectation that per unit G&A expenses will average between $0.12 to $0.16 per Mcfe for 2018;
the expectation that the Corporation's 2018 capital program will include drilling 29 (29.0 net) and completing
31 (31.0 net) wells;
the Corporation having adequate liquidity to fund working capital requirements and capital expenditures
through a combination of cash flows, available credit facilities, senior notes and convertible debentures;
expectations as to timing and outcome of the next review of the Corporation’s credit facilities;
expectations as to the estimated costs required to fulfill the Corporation's remaining contractual commitments
as at December 31, 2017;
expectations with respect to the declaration or payment of dividends;
expectations that future taxable income will be available to utilize accumulated tax pools;
expectations regarding future accounting pronouncements and their impact on the Corporation; and
expectations regarding the underlying claim filed by BRFN against the Province of British Columbia.
25
28
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
29
With respect to the forward-looking statements contained in this MD&A, assumptions have been made regarding:
•
•
•
•
•
the utilization of available credit facilities for 2018;
the validity of data used by GLJ Petroleum Consultants Ltd.(“GLJ”) in their independent reserves evaluation;
the continued adherence to contractual commitments;
the financial position of the applicable entities mitigating the risk of accounts receivable becoming
uncollectible; and
the cost structure of the Corporation.
Certain or all of the forward-looking statements may prove to be incorrect. These forward-looking statements represent
the Corporation’s views as of the date of this MD&A and such information should not be relied upon as representing
the Corporation’s views as of any date subsequent to the date of this MD&A. The Corporation has attempted to
identify important factors that could cause actual results, performance or achievements to vary from the current
expectations or estimates expressed or implied by the forward-looking statements contained herein. However, there
may be other factors that cause results, performance or achievements not to be as expected or estimated and that
could cause actual results, performance or achievements to differ materially from current expectations. Other risks
and uncertainties include, but are not limited to, the following:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
normal risks common to the oil and gas industry, including exploration, development and production
operations risks;
volatility of commodity prices;
changes in interest and foreign exchange rates;
risks and uncertainty of petroleum and natural gas geological deposits and reserves estimates;
health, safety and environmental risks;
revisions, amendments or changes to capital expenditure plans including exploration, development and
exploitation projects;
uncertainty of estimates and projections of production and costs;
unforeseen title defects;
risks arising from future acquisition activities;
restrictions contained in the Corporation’s credit facility;
uncertainty of the outcome of the underlying claim against the Province of British Columbia filed by the BRFN
and the risk of delays resulting from the need to change the location of planned activities and a potential
reduction in future volumes of natural gas and NGLs available for production by the Corporation;
risks as to the availability and pricing of appropriate financing alternatives on acceptable terms;
potential changes in income tax regulations, governmental policies, rules, practices or approval process
changes, or delays, or enhancements;
delays resulting from adverse weather conditions;
delays resulting from an inability to obtain required regulatory approvals and ability to access sufficient debt
or equity capital from internal and external sources; and
the Corporation’s ability to attract and retain qualified professional employees and consultants.
Statements relating to “reserves” or “resources” are by their nature deemed to be forward-looking statements, as
they involve the implied assessment based on certain estimates and assumptions that the resources and reserves
described can be profitably produced in the future.
There can be no assurance that the forward-looking statements contained herein will prove to be accurate, as results
and future events could differ materially from those expected or estimated in such statements. Accordingly, readers
should not place undue reliance on forward-looking statements. From time to time, Painted Pony’s management
makes estimates and forms opinions on which the forward-looking statements are based. The Corporation assumes
no obligation to update forward-looking statements if circumstances, management’s estimates, or opinions change,
unless prescribed by securities laws. Furthermore, readers should be aware that historical results are not necessarily
indicative of future performance.
Forecast Prices and Costs
Reserves estimates are calculated using the forecast price and cost assumptions by the reserves evaluator which
were in effect at the time of the applicable reserves evaluation. The complete GLJ January 1, 2018 price forecast
is available on its website at gljpc.com.
26
30
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
31
Gross Reserves
Unless otherwise stated, references to “reserves” are to the Corporation’s gross reserves, defined as the Corporation’s
working interest (operating or non-operating) share before deduction of royalties and without including any royalty
interests of the Corporation.
Estimated Future Net Revenues
Estimated future net revenues are stated before deducting income taxes and future estimated site restoration costs
and are reduced for estimated future abandonment costs and estimated capital for future development associated
with the reserves. The undiscounted and discounted net present values disclosed do not represent the fair market
value of the reserves.
Potential Transactions
Within its focus area, the Corporation regularly reviews potential property acquisitions and corporate merger and
acquisition opportunities for the purpose of determining whether any such potential transaction would benefit the
Corporation, as well as the terms on which such a potential transaction would be available. As a result, the Corporation
may from time to time be involved in discussions or negotiations with other parties or their agents in respect of
potential property acquisitions and corporate merger and acquisition opportunities. The Corporation is not committed
to any such potential transaction and cannot be reasonably confident that it can complete any such potential
transaction until appropriate legal documentation has been signed by the relevant parties.
BOE Conversions
Barrel of oil equivalent amounts have been calculated by using the conversion ratio of six thousand cubic feet (6
Mcf) of natural gas to one barrel of oil (1 bbl). Boe amounts may be misleading, particularly if used in isolation. A
boe conversion ratio of 6 Mcf to 1 bbl is based on an energy equivalency conversion method primarily applicable at
the burner tip and does not represent a value equivalency at the wellhead.
MCFE Conversions
Thousands of cubic feet of gas equivalent amounts have been calculated by using the conversion ratio of one barrel
of oil (1 bbl) to six thousand cubic feet (6 Mcf) of natural gas. Mcfe amounts may be misleading, particularly if used
in isolation. A conversion ratio of 1 bbl to 6 Mcf is based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value equivalency at the wellhead.
thousand cubic feet
thousand cubic feet per day
Abbreviations
Mcf
Mcf/d
MMcf/d million cubic feet per day
boe barrels of oil equivalent
boe/d barrels of oil equivalent per day
thousand barrels of oil equivalent
Mboe
bbls
barrels
bbls/d
NGLs
Mcfe
Mcfe/d
MMcfe/d
MMBtu
MMBtu/d
barrels per day
natural gas liquids
thousand cubic feet equivalent
thousand cubic feet equivalent per day
million cubic feet equivalent per day
million British thermal units
million British thermal units per day
ADDITIONAL INFORMATION
Additional information regarding the Corporation and its business and operations, including the AIF for the year ended
December 31, 2017 is available on the Corporation’s SEDAR profile at www.sedar.com. Copies of the Corporation’s
disclosure can also be obtained by contacting the Corporation at Painted Pony Energy Ltd., Suite 1800, 736 – 6
Avenue SW., Calgary, Alberta T2P 3T7 (Phone (403) 475-0440), by email at info@paintedpony.ca or on the
Corporation’s website at www.paintedpony.ca.
30
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
31
27
MANAGEMENT’S RESPONSIBILITY FOR CONSOLIDATED FINANCIAL STATEMENTS
Management of Painted Pony Energy Ltd. (the “Corporation”) is responsible for the preparation and integrity of the
accompanying consolidated financial statements and all other information contained in this report. The consolidated
financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”)
and include amounts that are based on management’s informed judgments and estimates where necessary.
The Corporation has established internal accounting control systems which are designed to provide reasonable
assurance regarding the reliability of the Corporation’s financial reporting and the preparation of the consolidated
financial statements together with the other financial information for external purposes in accordance with IFRS.
The Board of Directors, through its Audit & Risk Committee, monitors management’s financial and accounting policies
and practices and the preparation of these consolidated financial statements. The Audit & Risk Committee meets
periodically with the external auditors and management to review the work of each and the propriety of the discharge
of their responsibilities.
The Audit & Risk Committee reviews the consolidated financial statements of the Corporation with management and
the external auditors prior to submission to the Board of Directors for final approval. The Board of Directors also
reviews the consolidated financial statements before they are finalized. The Board of Directors has approved the
consolidated financial statements for the years ended December 31, 2017 and 2016.
The external auditors have full and free access to the Audit & Risk Committee to discuss auditing and financial
reporting matters. The Audit & Risk Committee reviews the independence of the external auditors and pre-approves
audit and permitted non-audit services and fees. The Shareholders have appointed KPMG LLP as the external
auditors of the Corporation, and in that capacity, they have audited the consolidated financial statements for the
years ended December 31, 2017 and 2016.
“signed”
Patrick R. Ward
President and CEO
March 7, 2018
“signed”
W. Derek Aylesworth
Senior Vice President and CFO
28
32
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
33
INDEPENDENT AUDITORS’ REPORT
To the Shareholders of Painted Pony Energy Ltd.
We have audited the accompanying consolidated financial statements of Painted Pony Energy Ltd, which comprise
the consolidated statements of financial position as at December 31, 2017 and December 31, 2016, the consolidated
statements of operations, changes in equity and cash flows for the years then ended, and notes, comprising a
summary of significant accounting policies and other explanatory information.
Management’s Responsibility for the Consolidated Financial Statements
Management is responsible for the preparation and fair presentation of these consolidated financial statements in
accordance with International Financial Reporting Standards, and for such internal control as management
determines is necessary to enable the preparation of consolidated financial statements that are free from material
misstatement, whether due to fraud or error.
Auditors’ Responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We
conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require
that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about
whether the consolidated financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the
consolidated financial statements. The procedures selected depend on our judgment, including the assessment of
the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making
those risk assessments, we consider internal control relevant to the entity’s preparation and fair presentation of the
consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but
not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes
evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made
by management, as well as evaluating the overall presentation of the consolidated financial statements.
We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis
for our audit opinion.
Opinion
In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial
position of Painted Pony Energy Ltd. as at December 31, 2017 and December 31, 2016, and its consolidated financial
performance and its consolidated cash flows for the years then ended in accordance with International Financial
Reporting Standards.
Chartered Professional Accountants
March 7, 2018
Calgary, Canada
29
32
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
33
PAINTED PONY ENERGY LTD.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
($000s)
As at
ASSETS
Current assets
Accounts receivable
Prepaid expenses and deposits
Fair value of risk management contracts (note 16)
Non-current assets
Fair value of risk management contracts (note 16)
Exploration and evaluation (note 5)
Property, plant and equipment (note 6)
Deferred tax (note 12)
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities
Share unit liability (note 15)
Fair value of risk management contracts (note 16)
Current portion of finance lease obligation (note 18)
Non-current liabilities
Fair value of risk management contracts (note 16)
Bank debt (note 7)
Senior notes (note 8)
Convertible debentures (note 9)
Decommissioning obligation (note 13)
Finance lease obligation (note 18)
Deferred tax (note 12)
EQUITY
Share capital (note 14)
Equity portion of convertible debentures (note 9)
Contributed surplus
Retained earnings (deficit)
December 31, 2017
December 31, 2016
39,115
1,664
65,016
105,795
22,552
159,004
1,744,292
—
2,031,643
66,931
2,004
553
3,282
72,770
294
149,228
141,613
44,887
46,811
487,578
7,772
950,953
1,015,235
2,382
55,203
7,870
1,080,690
2,031,643
29,568
1,109
—
30,677
1,269
114,251
1,158,198
32,560
1,336,955
54,903
3,401
46,020
—
104,324
15,768
200,836
—
—
29,857
360,860
—
711,645
687,701
—
52,115
(114,506)
625,310
1,336,955
Commitments (notes 18 & 19)
See accompanying notes to the consolidated financial statements.
Approved on behalf of the Board:
“signed” Joan E. Dunne
Director
“signed” Patrick R. Ward
Director
34
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
30
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
35
PAINTED PONY ENERGY LTD.
CONSOLIDATED STATEMENTS OF OPERATIONS
($000s, except per share amounts)
Revenue
Petroleum and natural gas
Royalties
Realized gain on risk management contracts (note 16)
Unrealized gain (loss) on risk management contracts (note 16)
Expenses
Operating
Transportation
General and administrative
Costs on acquisition of UGR Blair Creek Ltd. (note 4)
Share-based compensation (note 15)
Depletion and depreciation (note 6)
Income (loss) from operations
Finance expense (note 11)
Income (loss) before taxes
Deferred tax (expense) recovery (note 12)
Net income (loss) and comprehensive income (loss)
Years ended December 31,
2016
2017
249,186
(4,901)
244,285
44,002
146,465
434,752
59,834
39,197
16,482
5,497
481
83,887
205,378
229,374
(61,591)
167,783
(45,407)
122,376
121,580
(2,672)
118,908
19,912
(75,664)
63,156
34,535
15,894
10,566
—
5,778
43,329
110,102
(46,946)
(22,770)
(69,716)
17,859
(51,857)
Net income (loss) and comprehensive income (loss) per share: ($ per share)
Basic (note 10)
Diluted (note 10)
See accompanying notes to the consolidated financial statements.
0.87
0.85
(0.52)
(0.52)
31
34
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
35
PAINTED PONY ENERGY LTD.
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
($000s, except shares)
Years ended December 31, 2017 and 2016
Equity
portion of
convertible
debentures
Contributed
surplus
Retained
earnings /
(deficit)
Total equity
—
—
—
—
—
—
—
—
—
—
2,382
—
2,382
48,930
(62,649)
672,983
3,484
(299)
—
—
3,484
700
—
(51,857)
(51,857)
52,115
(114,506)
625,310
220,170
110,992
(3,730)
3,118
72
2,382
—
—
—
—
—
—
—
—
—
3,118
(30)
—
—
122,376
122,376
55,203
7,870
1,080,690
Balance at December 31, 2015
Share-based compensation
Stock options exercised (note 14)
Net loss and comprehensive loss
Balance at December 31, 2016
Acquisition of UGR Blair Creek Ltd. (note 4)
Issuance of shares (note 14)
Share issue costs, net of tax impact
Share-based compensation
Stock options exercised (note 14)
Issuance of convertible debentures,
net of tax impact (note 9)
Net income and comprehensive income
Number of
Common
Shares
Share
capital
100,030,942
686,702
—
127,250
—
100,158,192
41,000,000
19,820,000
—
—
17,500
—
—
—
999
—
687,701
220,170
110,992
(3,730)
—
102
—
—
Balance at December 31, 2017
160,995,692
1,015,235
See accompanying notes to the consolidated financial statements.
32
36
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
37
PAINTED PONY ENERGY LTD.
CONSOLIDATED STATEMENTS OF CASH FLOWS
($000s)
Cash flows from operating activities:
Net income (loss) and comprehensive income (loss)
Adjustments for:
Depletion and depreciation
Share-based compensation
Accretion expense
Deferred income tax expense (recovery)
Unrealized (gain) loss on risk management contracts
Decommissioning expenditures
Changes in non-cash working capital
Cash flows from investing activities:
Property, plant and equipment additions
Cash assumed on acquisition of UGR Blair Creek Ltd.
Changes in non-cash working capital
Cash flows from financing activities:
Issuance of shares
Exercise of stock options
Increase (repayment) in bank debt
Share issue costs
Issuance of senior notes
Issuance of convertible debentures
Changes in non-cash working capital
Change in cash and cash equivalents
Cash and cash equivalents, beginning of year
Cash and cash equivalents, end of year
See accompanying notes to the consolidated financial statements.
33
Years ended December 31,
2017
2016
122,376
(51,857)
83,887
2,205
1,794
45,407
(146,465)
—
(2,287)
106,917
(302,614)
864
(4,195)
(305,945)
110,992
72
(99,825)
(5,074)
141,115
47,718
4,030
199,028
—
—
—
43,329
2,864
550
(17,859)
75,664
(102)
(7,931)
44,658
(204,391)
—
20,609
(183,782)
—
700
137,210
—
—
—
1,214
139,124
—
—
—
36
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
37
PAINTED PONY ENERGY LTD.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As at and for the years ended December 31, 2017 and 2016
______________________________________________________________________________
1. REPORTING ENTITY
Painted Pony Energy Ltd.’s (“Painted Pony” or the “Corporation”) principal business activity is the exploration,
development and production of petroleum and natural gas resources in western Canada. The consolidated
financial statements of the Corporation as at and for the years ended December 31, 2017 and 2016 include the
accounts of the Corporation and its wholly owned subsidiaries, UGR Blair Creek Ltd. (from the date of acquisition
- see note 4) and Painted Rock Resources Ltd. The Corporation’s head office is located at 1800, 736 - 6th Avenue
S.W., Calgary, Alberta. On January 1, 2018, the wholly owned subsidiaries were amalgamated with the
Corporation.
2. BASIS OF PRESENTATION
The consolidated financial statements have been prepared in accordance with International Financial Reporting
Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). The consolidated
financial statements were authorized for issuance by the Board of Directors of the Corporation (the “Board”) on
March 7, 2018.
The consolidated financial statements have been prepared on the historical cost basis except for risk management
contracts and share and cash settled awards, which are measured at fair value. The methods used to measure
fair value are discussed in note 17.
These consolidated financial statements are presented in Canadian dollars, which is the Corporation’s and its
subsidiaries' functional currency.
The preparation of consolidated financial statements in conformity with IFRS requires management to make
judgments, estimates and assumptions that affect the application of accounting policies and the reported amounts
of assets, liabilities, income and expenses. Actual results may differ materially from these estimates.
Estimates and underlying assumptions are reviewed on an ongoing basis, with revisions to accounting estimates
recognized in the period in which the estimates are revised and in any applicable future periods.
(a) Critical Accounting Judgments
The following are critical judgments that management has made in the process of applying accounting
policies and that have the most significant effect on the amounts recognized in the consolidated financial
statements.
Cash-Generating Units
The Corporation’s assets are aggregated into cash-generating units (“CGU” or “CGUs”) for the purpose of
assessing impairment. CGUs are based on an assessment of the unit’s ability to generate independent
cash inflows. The determination of these CGUs was based on management’s judgment in regard to shared
infrastructure, geographical proximity, petroleum type and exposure to market risk and materiality. By their
nature, these assumptions are subject to management’s judgment and may impact the carrying value of the
Corporation’s net assets in future periods.
Impairment Indicators
Judgments are required to assess when impairment indicators exist and impairment testing is required. The
Corporation is required to consider information from both external sources (such as negative downturn in
commodity prices, significant adverse changes in the technological, market, economic or legal environment
in which the entity operates) and internal sources (such as downward revisions in reserves, significant
adverse effect on the financial and operational performance of a CGU, evidence of obsolescence or physical
damage to the asset). In determining the recoverable amount of assets, in the absence of quoted market
34
38
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
39
prices, impairment tests are based on estimates of reserves, production rates, future petroleum and natural
gas prices, future costs, discount rates, market value of land and other relevant assumptions.
The application of the Corporation’s accounting policy for exploration and evaluation (“E&E”) assets requires
management to make certain judgments as to future events and circumstances as to whether economic
quantities of reserves have been found.
Deferred Taxes
In determining its deferred tax provisions, the Corporation must apply judgment when interpreting and
applying tax laws and regulations. The determination of the appropriate rules may be uncertain for many
periods. The final outcome could result in amounts different from those initially recorded and could impact
tax expense in the periods where a determination is made. Judgments are also made by management to
determine the likelihood of whether deferred tax assets at the end of the reporting period will be realized
from future taxable income.
(b) Critical Accounting Estimates
The following are key estimates made by management affecting the measurement of balances and
transactions in these consolidated financial statements.
Impact of Reserves
Estimation of recoverable quantities of proved and probable reserves includes estimates regarding future
commodity prices, exchange rates, discount rates and production and transportation costs for future cash
flows as well as the interpretation of complex geological and geophysical models and data. Changes in
expected future cash flows in reported reserves can affect the impairment of assets, the decommissioning
obligation, the economic feasibility of E&E assets and the amounts reported for depletion and depreciation
of property, plant and equipment (“PP&E”), and the recognition of deferred tax assets. These reserve
estimates are prepared in accordance with the Canadian Oil and Gas Evaluation Handbook and are verified
by independent qualified reserve evaluators, who work with information provided by the Corporation to
establish reserve determinations in accordance with National Instrument 51-101 - Standards of Disclosure
for Oil and Gas Activities (“NI 51-101”).
In a business combination, management makes estimates of the fair value of assets acquired and liabilities
assumed which includes assessing the value of petroleum and natural gas properties based upon the
estimation of recoverable quantities of proved and probable reserves being acquired.
Share-Based Compensation
All equity-settled, share-based awards issued by the Corporation are fair valued using the Black-Scholes
option-pricing model. In assessing the fair value of equity-based compensation, estimates have to be made
regarding the expected volatility in share price, option life, dividend yield, risk-free rate and estimated
forfeitures at the initial grant date.
Derivative Financial Instruments
Painted Pony records risk management contracts at fair value with changes in fair value recognized in the
consolidated statements of operations. The Corporation’s estimate of the fair value is determined using
observable market data and external counterparty information, including estimated forward prices and
volatility in those prices.
Decommissioning Obligation
The Corporation estimates future remediation costs of production facilities, wells and pipelines at different
stages of development and construction of assets or facilities. In most instances, removal of assets occurs
many years into the future. This requires estimates regarding abandonment date, future environmental and
regulatory legislation, the extent of reclamation activities, the engineering methodology for estimating cost,
future removal technologies in determining the removal cost and liability-specific discount rates to determine
the present value of these cash flows.
Deferred Taxes
Tax provisions are based on enacted or substantively enacted laws. Changes in those laws could affect
amounts recognized in income or loss both in the period of change, which would include any impact on
cumulative provisions, and in future periods.
35
38
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
39
Deferred tax assets are recognized only to the extent it is considered probable that those assets will be
recoverable. This involves an assessment of when those deferred tax assets are likely to reverse and a
judgment as to whether or not there will be sufficient taxable income available to offset the tax assets when
they do reverse. This requires assumptions regarding future profitability and is therefore inherently uncertain.
Estimates of future taxable income are based on forecasted cash flows from operations.
3. SIGNIFICANT ACCOUNTING POLICIES
The accounting policies set out below have been applied consistently to all years presented in these consolidated
financial statements, by both the Corporation and its subsidiaries.
(a) Basis of Consolidation
Subsidiaries
Subsidiaries are entities controlled by the Corporation. Control exists when the Corporation has the power
to govern the financial and operating policies of an entity so as to obtain benefits from its activities. In
assessing control, potential voting rights that currently are exercisable are taken into account. The financial
statements of subsidiaries are included in the consolidated financial statements from the date that control
commences until the date that control ceases.
Business Combinations
The purchase method of accounting is used to account for acquisitions of subsidiaries and assets that meet
the definition of a business under IFRS. The cost of an acquisition is measured as the fair value of the assets
given, equity instruments issued and liabilities incurred or assumed at the date of exchange. Identifiable
assets acquired and liabilities and contingent liabilities assumed in a business combination are measured
initially at their fair values at the acquisition date. The excess of the cost of acquisition over the fair value of
the identifiable assets, liabilities and contingent liabilities acquired is recorded as goodwill. If the cost of
acquisition is less than the fair value of the net assets of the subsidiary acquired, the difference is recognized
immediately in the consolidated statement of operations.
Jointly Controlled Operations and Jointly Controlled Assets
A portion of the Corporation’s petroleum and natural gas activities involve jointly controlled assets. The
consolidated financial statements include the Corporation’s share of these jointly controlled assets and a
proportionate share of the relevant revenue and related costs.
Transactions Eliminated on Consolidation
Intercompany balances and transactions, and any unrealized income and expenses arising from
intercompany transactions, are eliminated in preparing the consolidated financial statements.
(b) Financial instruments
Non-Derivative Financial Instruments
Non-derivative financial instruments comprise accounts receivable, accounts payable and accrued liabilities,
bank debt, senior notes and convertible debentures. Non-derivative financial instruments are recognized
initially at fair value plus, for instruments not at fair value through comprehensive income or loss, any directly
attributable transaction costs. Subsequent to initial recognition, non-derivative financial instruments are
measured as described below.
Accounts receivable, accounts payable and accrued liabilities, bank debt, senior notes and convertible
debentures are measured at amortized cost using the effective interest rate method, less any impairment
losses.
Compound Financial Instruments
The Corporation's compound financial instruments are comprised of its convertible debentures that can be
converted into common shares in the capital of the Corporation (“Common Share” or "Common Shares") at
36
40
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
41
the option of the holder. The liability component of the convertible debentures is recognized initially at fair
value of a similar liability that does not have an equity conversion option. The equity component is recognized
initially as the difference between the fair value of the convertible debenture and the fair value of the liability
component. Any directly attributable transaction costs are allocated to the liability and equity components
in proportion to their initial carrying values. Subsequent to initial recognition the liability component of the
convertible debentures is measured at amortized cost using the effective interest rate method. The equity
component of the convertible debentures is not re-measured subsequent to initial recognition.
Derivative Financial Instruments
The Corporation has entered into certain financial risk management contracts in order to manage the
exposure to market risks from fluctuations in commodity prices and foreign currency. These instruments are
not used for trading or speculative purposes. The Corporation has not designated its financial risk
management contracts as effective accounting hedges and, therefore, has not applied hedge accounting,
even though the Corporation considers all risk management contracts to be economic hedges. As a result,
all financial risk management contracts are classified as fair value through profit or loss and are recorded
on the consolidated statement of financial position at fair value. Transaction costs are recognized in income
or loss when incurred.
The Corporation has issued deferred share units (“DSU” or “DSUs”) to members of the Board and eligible
executive officers. Each DSU is a notional unit equal in value to a Common Share, which entitles the holder
to a cash payment upon redemption. DSUs are measured at fair value upon grant and each period end date,
using the 20-day volume weighted average price of Common Shares. DSUs are classified as fair value
through profit or loss and are recorded on the consolidated statement of financial position at fair value.
The Corporation has issued preferred share units ("PSU" or "PSUs") to eligible executive officers. Each
PSU is a notional unit equal in value to a Common Share, which entitles the holder to a cash payment upon
redemption. PSUs are measured at fair value through profit or loss and are recorded on the consolidated
statement of financial position at fair value.
The Corporation has issued restricted share units ("RSU" or "RSUs") to eligible employees. Each RSU is
a notional unit equal in value to a Common Share, which entitles the holder to a cash payment on redemption.
RSUs are measured at fair value through profit or loss and are recorded on the consolidated statement of
financial position at fair value.
(c) Exploration and Evaluation Assets and Property, Plant and Equipment
Recognition and Measurement
(i) Exploration and evaluation assets
Pre-license costs are expensed as incurred. E&E costs, including the costs of acquiring licenses, seismic,
exploration drilling and directly attributable general and administrative costs initially are capitalized as
E&E assets according to the nature of the assets acquired. The costs are accumulated in cost centers
pending determination of technical feasibility and commercial viability.
The technical feasibility and commercial viability of extracting a mineral resource is considered to be
determinable when proved or probable reserves are determined to exist. A review is carried out, on a
quarterly basis, to ascertain whether proved or probable reserves have been discovered. Upon
determination of proved or probable reserves, E&E assets attributable to those reserves are first tested
for impairment and then reclassified from E&E assets to PP&E.
(ii) Property, plant and equipment
Items of PP&E, which include petroleum and natural gas development and production assets, and finance
lease assets, are measured at cost less accumulated depletion, depreciation and accumulated
impairment losses. Development and production assets are grouped into CGUs for impairment testing.
When significant parts of an item of PP&E, including petroleum and natural gas interests, have different
useful lives, they are accounted for as separate items.
37
40
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
41
Gains and losses on disposal of PP&E, are determined by comparing the proceeds from disposal, or
fair value or properties received, with the carrying amount of the asset and are recognized in income or
loss.
Costs incurred subsequent to the determination of technical feasibility and commercial viability and the
costs of replacing parts of PP&E are recognized as petroleum and natural gas interests only when they
increase the future economic benefits embodied in the specific assets to which they relate. All other
expenditures are recognized in income or loss as incurred. Such capitalized petroleum and natural gas
interests generally represent costs incurred in developing proved and/or probable reserves and bringing
on or enhancing production from such reserves. The carrying amount of any replaced or sold component
is derecognized. The costs of periodic servicing of PP&E are recognized in income or loss.
Depletion and Depreciation
The net carrying value of development or production assets and finance lease assets are depleted using
the unit of production method by reference to the ratio of production in the period to the related proved and
probable reserves, taking into account estimated future development costs necessary to bring those reserves
into production. Future development costs are estimated taking into account the level of development required
to produce the reserves. These estimates are reviewed by independent reserve engineers on an annual
basis, at a minimum.
Proved and probable reserves are estimated using independent reserve engineer reports in accordance
with NI 51-101 and represent the estimated quantities of petroleum, natural gas and natural gas liquids which
geological, geophysical and engineering data demonstrate with a specified degree of certainty to be
recoverable in future years from known reservoirs and which are considered commercially producible. There
should be a 50 percent statistical probability that the actual quantity of recoverable reserves will be more
than the amount estimated as proved and probable and a 50 percent statistical probability that it will be less.
The equivalent statistical probabilities for proved reserve components are 90 percent and 10 percent,
respectively.
Such reserves may be considered commercially producible if management has the intention of developing
and producing them and such intention is based upon:
•
•
•
a reasonable assessment of the future economics of such production;
a reasonable expectation that there is a market for all or substantially all the expected petroleum and
natural gas production; and
evidence that the necessary production, transmission and transportation facilities are available or can
be made available.
In determining reserves for use in the depletion and impairment calculations, a barrel of oil equivalent (“boe”)
conversion ratio of six thousand cubic feet of gas (“Mcf”) to one barrel of oil (“bbl”) (6 Mcf:1 bbl) is used as
an energy equivalency conversion method.
For other assets, depreciation is recognized in income or loss on a declining-balance rate of 20% based on
their estimated useful lives. E&E assets are not depreciated.
(d) Impairment
Financial Assets
A financial asset is assessed at each reporting date to determine whether there is any objective evidence
that it is impaired. A financial asset is considered to be impaired if objective evidence indicates that one or
more events have had a negative effect on the estimated future cash flows of that asset.
An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference
between its carrying amount and the present value of the estimated future cash flows discounted at the
original effective interest rate.
38
42
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
43
Individually significant financial assets are tested for impairment on an individual basis. The remaining
financial assets are assessed collectively in groups that share similar credit risk characteristics. All impairment
losses are recognized in income or loss.
An impairment loss is reversed if the reversal can be related objectively to an event occurring after the
impairment loss was recognized. For financial assets measured at amortized cost the reversal is recognized
in income or loss.
Non-financial Assets
The carrying amounts of the Corporation’s non-financial assets, other than E&E assets and deferred tax
assets, are reviewed whenever there is an indication of impairment. If any such indication exists, the asset’s
recoverable amount is estimated.
For the purpose of impairment testing, assets are grouped together into CGUs, being the smallest group of
assets that generate cash inflows from continuing use that are largely independent of the cash inflows of
other assets or groups of assets. The recoverable amount of an asset or a CGU is the greater of its value
in use and its fair value less costs of disposal.
Fair value less costs of disposal is derived by estimating the discounted after-tax future net cash flows from
proved plus probable oil and gas reserves, adjusted for the discounted abandonment and reclamation costs
on proved plus probable undeveloped oil and gas reserves. Discounted future net cash flows are based on
forecasted commodity prices and costs over the expected economic life of the reserves and discounted
using market-based rates to reflect a market participant’s view of the risks associated with the assets. Value
in use is assessed using the expected future cash flows from proved plus probable oil and gas reserves
discounted at a pre-tax rate, adjusted for the discounted abandonment and reclamation costs associated
with wells without reserves and facilities that relate to the CGUs.
E&E assets are assessed for impairment if: (i) sufficient data exists to determine technical feasibility and
commercial viability, or (ii) facts and circumstances suggest that the carrying amount exceeds the recoverable
amount.
An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated
recoverable amount. Impairment losses are recognized in income or loss. For purposes of impairment testing,
E&E assets are combined with cash-generating units.
Impairment losses recognized in prior years are assessed at each reporting date for any indications that the
loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the
estimates used to determine the recoverable amount. An impairment loss is reversed only to the extent that
the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of
depletion and depreciation, if no impairment loss had been recognized.
(e) Leased Assets
Payments made under operating leases are recognized in income or loss on a straight-line basis (or as
otherwise contractually defined) over the term of the lease. Lease incentives received are recognized as
part of the total lease expense over the term of the lease.
Leases which transfer substantially all of the risks and rewards of ownership are classified as finance leases.
On initial recognition, the leased asset is measured at an amount equal to the lower of its fair value and the
present value of the minimum lease payments. Subsequent to initial recognition, the asset is accounted for
in accordance with the accounting policy applicable to the asset. Minimum lease payments are apportioned
between the finance expense and the reduction of the outstanding liability. The finance expense is allocated
to each period during the lease term so as to produce a constant periodic rate of interest on the remaining
balance of the liability.
(f) Share Capital
Common Shares are classified as equity. Incremental costs directly attributable to the issue of shares and
stock options are recognized as a deduction from equity, net of tax.
39
42
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
43
(g) Share-Based Compensation
The Corporation has issued stock options to acquire Common Shares to directors, executive officers and
employees. The fair value of stock options on the date they are granted is recognized as share-based
compensation expense with a corresponding increase in contributed surplus over the vesting period. A
forfeiture rate is estimated on the grant date, and the expense is adjusted to reflect actual forfeitures
throughout the vesting period. The Corporation uses the Black-Scholes model to estimate fair value.
The Corporation has issued DSUs, PSUs and RSUs. The DSUs, PSUs and RSUs are accounted for as
cash-settled, share-based payment plans. The fair value of the amount payable under the DSU, PSU, and
RSU plans are recognized as an expense with a corresponding increase in liabilities. The liability is calculated
at each reporting date and at settlement date. Any changes in the fair value of the liability are recognized
in the consolidated statement of operations.
A portion of share-based compensation directly attributable to the exploitation and development of the
Corporation's assets is capitalized.
(h) Provisions
A provision is recognized if, as a result of a past event, the Corporation has a present legal or constructive
obligation that can be estimated reliably and it is probable that an outflow of economic benefits will be required
to settle the obligation. Provisions are determined by discounting the expected future cash flows at a pre-
tax risk free rate.
Decommissioning Obligation
The Corporation’s activities give rise to dismantling, decommissioning and site disturbance remediation
activities. Provision is made for the estimated cost of site restoration and is capitalized in the relevant asset
category.
The decommissioning obligation is measured at the present value of management’s best estimate of the
expenditure required to settle the present obligation at the reporting date. Subsequent to the initial
measurement, the obligation is adjusted at the end of each period to reflect the passage of time and changes
in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage
of time is recognized as a finance expense whereas increases/decreases due to changes in the estimated
future cash flows are capitalized. Actual costs incurred upon settlement of the decommissioning obligation
are charged against the provision to the extent the provision had been established.
(i) Revenue Recognition
Revenue from the sale of petroleum and natural gas is recorded when the significant risks and rewards of
ownership of the product are transferred to the buyer, which is usually when legal title passes to the external
party, and when collection is reasonably assured.
(j) Finance Expense
Finance expense consists of interest expense and standby fees on credit facilities, costs related to the
implementation of the credit facilities, accretion on the decommissioning obligation, senior notes and
convertible debentures, and costs associated with the finance lease obligation.
(k) Income Tax
Income tax expense comprises current and deferred tax expense and is recognized in net income or loss
except to the extent that it relates to items recognized directly in equity.
Deferred tax is recognized using the balance sheet method, providing for temporary differences between
the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for
taxation purposes. Deferred tax is not recognized on the initial recognition of assets or liabilities in a transaction
that is not a business combination. Deferred tax is measured at the tax rates that are expected to be applied
to temporary differences when they reverse, based on the laws that have been enacted or substantively
enacted by the reporting date. Deferred tax assets and liabilities are offset if there is a legally enforceable
right to offset, and they relate to income taxes levied by the same tax authority on the same taxable entity,
40
44
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
45
or on different tax entities, but they intend to settle current tax liabilities and assets on a net basis or their
tax assets and liabilities will be realized simultaneously.
A deferred tax asset is recognized to the extent that it is likely that future taxable income will be available
against which the temporary difference can be utilized. Deferred tax assets are reviewed at each reporting
date and are reduced to the extent that it is no longer likely that the related tax benefit will be realized.
(l) Foreign Currency Translation
The principal currency of the economic environment in which the Corporation and its wholly owned
subsidiaries operate is the Canadian dollar. Monetary assets and liabilities denominated in foreign currencies
are translated into Canadian dollars at exchange rates in effect at the end of the period, and revenues and
expenses are translated into Canadian dollars at average exchange rates. All translation gains and losses
are recorded in income or loss.
(m) Per Share Information
Basic per share information is calculated on the basis of the weighted average number of Common Shares
outstanding during the period. Diluted per share information reflects the potential dilutive effect of stock
options and convertible debentures. Anti-dilutive instruments are not included in the determination of diluted
income (loss) per share.
(n) Future Accounting Pronouncements
A number of new accounting standards, amendments to accounting standards and interpretations are
effective for annual periods beginning on or after January 1, 2018 and have not been applied in preparing
the consolidated financial statements for the year ended December 31, 2017. The standards applicable to
the Corporation are as follows and will be adopted on their respective effective dates:
Financial Instruments
In July 2014, the IASB issued the final version of IFRS 9 “Financial Instruments”, which replaces IAS 39
“Financial Instruments: Recognition and Measurement”. The standard will come into effect for annual periods
beginning on or after January 1, 2018 with earlier adoption permitted.
IFRS 9 introduces a single approach to determine whether a financial asset is measured at amortized cost
or fair value and replaces the multiple rules in IAS 39. The approach is based on how an entity manages its
financial instruments in the context of its business model and the contractual cash flow characteristics of the
financial assets. For financial liabilities, IFRS 9 retains most of the requirements of IAS 39; however, where
the fair value option is applied to financial liabilities, any change in fair value resulting from an entity’s own
credit risk is recorded in other comprehensive income ("OCI") rather than the statement of operations, unless
this creates an accounting mismatch. Based on its preliminary assessment, the Corporation does not
anticipate these changes to have a material impact on its consolidated financial statements.
In addition, IFRS 9 introduces a new expected credit loss model for calculating impairment of financial assets,
replacing the incurred loss impairment model required by IAS 39. The new model will result in more timely
recognition of expected credit losses. Painted Pony does not anticipate the new impairment model to have
a material impact on the consolidated financial statements.
IFRS 9 also contains a new model to be applied for hedge accounting, aligning hedge accounting more
closely with risk management. The Corporation does not currently apply hedge accounting to its risk
management contracts and does not currently intend to apply hedge accounting to any of its existing risk
management contracts on adoption of IFRS 9.
Revenue Recognition
As of January 1, 2018, the Corporation has adopted IFRS 15 “Revenue from Contracts with Customers”,
which replaces IAS 18 “Revenue”. The standard provides a single, principles based 5 step model to be
applied to all contracts with customers. The standard requires an entity to recognize revenue to reflect the
transfer of goods and services for the amount it expects to receive, when control is transferred to the
purchaser. Disclosure requirements have also been expanded.
41
44
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
45
The standard has been adopted using a modified retrospective approach as of January 1, 2018. The
Corporation has reviewed its revenue streams and underlying contracts with customers and has determined
that there will not be a material impact on its earnings. Additional disclosure will be implemented.
Leases
In January 2016, the IAS issued IFRS 16 “Leases”, which replaces IAS 17 “Leases”, and provides that a
single recognition and measurement model for leases would apply, with required recognition of assets and
liabilities for most leases. For lessees, IFRS 16 removes the classification of leases as either operating or
finance leases, effectively treating all leases as finance leases. Certain short-term leases (less than 12
months) and leases of low-value assets are exempt from the requirements, and may continue to be treated
as operating leases.
IFRS 16 is effective for years beginning on or after January 1, 2019, with early adoption permitted if IFRS
15 “Revenue from Contracts with Customers” has been adopted. The standard may be applied retrospectively
or using a modified retrospective approach. It is anticipated that the adoption of IFRS 16 will have an impact
on the Corporation’s consolidated statement of financial position.
4. ACQUISITION OF UGR BLAIR CREEK LTD.
Effective May 16, 2017, the Corporation acquired all of the issued and outstanding shares of UGR Blair Creek
Ltd. ("UGR") in exchange for the issuance of 41.0 million Common Shares of the Corporation with an assigned
value of $220.2 million. The Common Shares were ascribed a fair value of $5.37 per Common Share issued,
as determined based on the Corporation's closing share price at the date of closing, being May 16, 2017. The
UGR acquisition is a strategic expansion of the Corporation's Montney project in NEBC, providing for an expansion
of the Corporation's land base, natural gas processing infrastructure, reserves and drilling inventory. The
operations from the UGR acquisition have been included in the results of the Corporation commencing May 16,
2017. Acquisition costs of $5.5 million were expensed through the consolidated statement of operations. The
UGR acquisition was accounted for using the purchase method of accounting. The allocation of the purchase
price, based on management's estimates of fair values, is as follows:
($000s)
Fair value of the net assets acquired:
Cash
Other current assets
Current liabilities
Risk management contracts
Property, plant and equipment
Exploration and evaluation
Bank debt
Decommissioning obligation
Deferred tax asset
Net assets acquired
Consideration:
Common Shares (41.0 million shares @ $5.37/share)
864
5,884
(8,865)
775
207,491
58,743
(48,217)
(1,093)
4,588
220,170
220,170
On acquisition, the Corporation recorded the decommissioning obligation at a credit adjusted risk free rate
resulting in a decommissioning obligation totaling $1.1 million. Subsequent to the date of acquisition, the
decommissioning obligation was revalued using the risk free rate, resulting in an adjustment of $7.1 million,
with a corresponding increase to property, plant and equipment.
42
46
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
47
Included in the consolidated statement of operations are the following amounts relating to the UGR acquisition
from May 16, 2017 to December 31, 2017.
($000s)
Revenue
Net income and comprehensive income
24,542
10,115
If the UGR acquisition had occurred on January 1, 2017, the Corporation's estimated pro forma results of
revenue and net income and comprehensive income for the year ended December 31, 2017 would have been
as follows:
($000s)
Revenue
Net income and comprehensive income
5. EXPLORATION AND EVALUATION ASSETS
($000s)
As at December 31, 2015
Transfer to property, plant and equipment
As at December 31, 2016
UGR acquisition (note 4)
Transfer to property, plant and equipment
As at December 31, 2017
Painted Pony
Energy Ltd.
249,186
122,376
UGR acquisition
(January 1, 2017
to closing date) Pro forma results
17,868
5,765
267,054
128,141
116,145
(1,894)
114,251
58,743
(13,990)
159,004
Exploration and evaluation assets consist of undeveloped lands and unevaluated seismic data on the
Corporation’s exploration projects which are pending the determination of proved or probable reserves. Additions
represent the Corporation’s share of costs incurred on E&E assets during the period. Transfers are made to
PP&E as proved or probable reserves are determined. E&E assets are expensed due to non-economic drilling
and completion activities and lease expiries. The Corporation assesses the recoverability of E&E assets on the
transfer to PP&E.
46
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
47
43
6. PROPERTY, PLANT & EQUIPMENT
($000s)
Cost:
As at December 31, 2015
Capital expenditures
Non-cash additions
Finance lease assets
Transfer from exploration and evaluation
As at December 31, 2016
Capital expenditures
UGR acquisition (note 4)
Finance lease assets
Non-cash additions
Transfer from exploration and evaluation
As at December 31, 2017
Accumulated depletion and depreciation:
As at December 31, 2015
Depletion and depreciation
As at December 31, 2016
Depletion and depreciation
As at December 31, 2017
Carrying amounts:
December 31, 2016
December 31, 2017
802,392
204,391
8,549
360,860
1,894
1,378,086
302,614
207,491
130,000
15,886
13,990
2,048,067
176,559
43,329
219,888
83,887
303,775
1,158,198
1,744,292
Estimated future development costs associated with the development of the Corporation’s proved plus probable
reserves at December 31, 2017 and at December 31, 2016 were $4.1 billion and $2.9 billion, respectively.
Property Swap
On July 27, 2016, Painted Pony announced that it had entered into a non-cash asset exchange agreement, in
respect of acreage, wells and non-operated facility interests, with a large industry partner on jointly held acreage
in the Daiber, Cameron and Blair Creek areas of British Columbia. The asset exchange closed on September
26, 2016, with an effective date of January 1, 2016. Adjustments between the effective and closing dates are
included in PP&E as property dispositions. Management performed an assessment of the exchange agreement,
and concluded that the transaction did not meet the criteria to record an accounting gain or loss.
Capitalized General and Administrative Expense, Recoveries and Share-Based Compensation
($000s)
General and administrative
Capital recoveries
Share-based compensation
Total
44
Years ended December 31,
2016
2017
5,937
5,764
2,343
3,339
620
913
8,900
10,016
48
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
49
7. BANK DEBT
At December 31, 2017, the Corporation’s syndicated credit facilities consisted of available credit facilities of $450
million. The available facilities are provided by a syndicate of financial institutions, and include a $400 million
extendable revolving facility and a $50 million operating facility. The facilities revolve for a 2-year period, which
is extendable annually, subject to syndicate approval. The facilities are subject to semi-annual review and re-
determination of borrowing base by April 30 and October 31 of each year, or in the circumstance of a material
adverse change. Any re-determination of the borrowing base is effective immediately, and if the borrowing base
is reduced, the Corporation has 60 days to repay any shortfall.
As at December 31, 2017, Painted Pony had $160 million in bankers’ acceptances with an effective interest rate
of 3.65% per annum. In addition, as at December 31, 2017 the Corporation had outstanding letters of credit
totaling $21.5 million and US$15.0 million, which reduce the credit available on the syndicated facilities. At
December 31, 2016, the Corporation had an outstanding letter of credit of $14.9 million.
The credit facilities bear interest on a matrix system that ranges from the bank’s prime rate plus 1.0% to the
bank’s prime rate plus 3.25% per annum depending on the Corporation’s senior debt to quarterly annualized
EBITDA ratio as defined by the lenders, ranging from less than 1.00:1 to 3.00:1. The credit facilities provide that
advances may be made by way of prime rate loans, U.S. Base Rate loans, London InterBank Offered Rate loans,
bankers’ acceptances, letters of credit or letters of guarantee. A standby fee of 0.5% to 0.8125% per annum is
charged on the undrawn portion of the credit facilities, also calculated depending on the Corporation’s senior
debt to quarterly annualized EBITDA ratio, as defined by the lenders.
Security over all of the Corporation’s assets is provided by a floating charge demand debenture in the aggregate
amount of $1.0 billion. The Corporation has provided a negative pledge and an undertaking to provide fixed
charges over its petroleum and natural gas reserves in certain circumstances. The Corporation's syndicated
credit facilities include financial covenants as follows: senior debt to EBITDA ratio of not greater than 3.00:1 on
a trailing four fiscal quarter basis, and total debt to EBITDA ratio of not greater than 4.25:1 on a trailing four fiscal
quarter basis until Q2 2018, thereafter of not greater than 4.00:1 on a trailing four fiscal quarter basis. At
December 31, 2017 the senior debt to EBITDA ratio was 1.77:1.00, and the total debt to EBITDA ratio was
3.28:1.00. The Corporation is in compliance with all covenants as at December 31, 2017.
8. SENIOR NOTES
On August 23, 2017, the Corporation issued $150.0 million of 8.5% senior unsecured notes (the "Notes") with
a 5 year term by way of private placement. Proceeds net of discount and transaction costs of $8.9 million
amounted to $141.1 million. Interest is payable in equal quarterly installments in arrears. The Notes are fully and
unconditionally guaranteed as to the payment of principal and interest, on a senior unsecured basis by the
Corporation. There are no maintenance financial covenants.
The Notes are non-callable by the Corporation prior to the three year anniversary. If the Corporation chooses to
redeem the Notes prior to August 23, 2020, they will be subject to a make-whole premium equal to the Canada
Yield Price, plus accrued and unpaid interest. At any time on or after August 23, 2020, the Corporation can
redeem all or part of the Notes at the redemption prices set forth in the table below plus any accrued and unpaid
interest.
Redemption Schedule
August 23, 2020 - August 22, 2021
August 23, 2021 - February 22, 2022
February 23, 2022 - August 23, 2022
Percentage
104.250%
102.125%
100.000%
If a change of control event occurs at any time before maturity, the Corporation must offer to repurchase the
Notes at a price according to the redemption schedule above.
45
48
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
49
The Notes were recorded at their fair value on the date of issuance of $141.1 million. Accretion of the liability
will be included in finance expense in the consolidated statement of operations. At December 31, 2017 the
carrying value of the Notes was $141.6 million and accretion expense of $0.5 million was recorded in the
consolidated statement of operations.
9. CONVERTIBLE DEBENTURES
($000s)
Balance at December 31, 2016
Issuance of convertible debentures
Issue costs
Deferred tax liability
Accretion of discount
Balance at December 31, 2017
Liability component
—
Equity component
—
46,607
(2,128)
—
408
44,887
3,393
(154)
(857)
—
2,382
On August 23, 2017, the Corporation issued $50.0 million of convertible unsecured subordinated debentures
(the "Debentures") for net proceeds of $47.7 million. The Debentures mature on August 23, 2021 and bear
interest at 6.5% per annum payable quarterly. At the holder's option, the Debentures may be converted into
Common Shares of the Corporation at any time prior to the close of business on the date of maturity at a
conversion price of $5.60 per share (the "conversion price").
The Debentures are non-redeemable by the Corporation between August 23, 2017 and February 22, 2020 other
than pursuant to the 90% redemption right (see change of control below). The Debentures are redeemable by
the Corporation between February 23, 2020 and August 23, 2021 at a redemption price equal to the principal
amount plus interest. Redemption may be satisfied in Common Shares if the 30-day volume weighted average
price ("VWAP") on notice date and the closing price immediately prior to notice date are both greater than 140%
of the conversion price.
On maturity, the Corporation may satisfy its obligation to Debenture holders by issuing Common Shares if the
Corporation's market capitalization exceeds $750 million. The number of Common Shares issued is calculated
based on 95% of the lesser of the 30-day VWAP and the 2-day VWAP on the date of maturity.
Upon occurrence of a change of control event, the Corporation must offer to repurchase the Debentures at a
price according to the schedule below. If 90% or more of the principal amount accept the offer, the Corporation
shall have the right to repurchase 100% of the Debentures outstanding.
Redemption Schedule
August 23, 2017 - August 22, 2018
August 23, 2018 - February 22, 2020
February 23, 2020 - August 23, 2021
Percentage of
Principal
110.000%
105.000%
100.000%
The liability component of the Debentures was recognized initially at the fair value of a similar liability that does
not have an equity conversion option, which was calculated based on a market interest rate of 8.5%. The difference
between the $50.0 million principal amount of the Debentures and the fair value of the liability component was
recognized in shareholder's equity, net of deferred taxes. Total transaction costs directly attributable to the offering
of $2.3 million were allocated to the liability and equity components of the Debentures proportionately.
Accretion of the liability component and accrued interest payable on the Debentures are included in accretion
and financing expense respectively, in the consolidated statement of operations. At December 31, 2017 the
carrying value of the Debentures was $44.9 million.
46
50
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
51
10. NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) PER SHARE
($000s, except shares and per share amounts)
Years ended December 31,
Net income (loss) and comprehensive income (loss)-basic
Net income (loss) and comprehensive income (loss)-diluted
2017
122,376
123,227
2016
(51,857)
(51,857)
Weighted average Common Shares-basic
Weighted average Common Shares-diluted
140,717,740
144,149,853
100,069,546
100,069,546
Net income (loss) per share - basic ($/share)
Net income (loss) per share - diluted ($/share)
0.87
0.85
(0.52)
(0.52)
The average market value of the Common Shares for purposes of determining the dilutive effect of outstanding
stock options was based on quoted market prices for the year. For the year ended December 31, 2017, there
were 252,074 stock options were included in the weighted-average diluted share calculation of Common Shares.
For the year ended December 31, 2016, all stock options were excluded from the weighted-average diluted
share calculation of Common Shares as they were anti-dilutive.
The Common Shares potentially issuable on conversion of the Debentures were included in diluted net income
and comprehensive income per share. For the year ended December 31, 2017, 3,180,039 potential Common
Shares (December 31, 2016 - nil) were included in diluted net income and comprehensive income per share.
11. FINANCE EXPENSE
($000s)
Finance lease expense (note 18)
Interest expense
Accretion
Total
Years ended December 31,
2016
2017
14,165
44,157
15,640
1,794
61,591
8,055
550
22,770
Finance lease expense is a component of the capital fee paid on facilities treated as a capital lease, and varies
with production volumes processed. The capital fee includes finance lease expense and any amortization of the
outstanding finance lease obligation. Interest expense includes interest on bank debt and standby charges on
the Corporation’s syndicated credit facilities, as well as interest on the senior notes and convertible debentures.
Accretion expense consists of accretion on the decommissioning obligation, senior notes and convertible
debentures.
47
50
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
51
12. DEFERRED TAX
Reconciliation of effective tax rate:
($000s)
Years ended December 31,
Income (loss) before taxes
Combined corporate tax rate
Expected tax reduction
Non-deductible expenses
Non-deductible share-based compensation
Change in statutory rates and true-ups
Other
2017
167,783
26.5%
44,462
337
584
14
10
2016
(69,716)
26.5%
(18,475)
45
759
(214)
26
Total deferred tax expense (recovery)
45,407
(17,859)
Deferred tax assets and liabilities are attributable to the following:
($000s)
Deferred tax liabilities:
PP&E and E&E assets
Fair value of risk management contracts
Senior notes
Convertible debentures
Other
Less deferred tax assets:
Non-capital losses
Fair value of risk management contracts
Decommissioning obligation
Finance costs
Other
Net deferred tax (liability) asset
December 31, 2017
December 31, 2016
(101,559)
(23,415)
(1,049)
(465)
(382)
(69,174)
—
—
—
—
(126,870)
(69,174)
103,327
—
12,639
3,132
—
(7,772)
75,897
16,038
7,912
—
1,887
32,560
The Corporation has non-capital losses of $382.7 million which expire in the years 2026 through 2035. The
Corporation has determined that it is likely that these losses will be utilized against future taxable income. Total
tax pools at December 31, 2017 were $1.4 billion (December 31, 2016 – $0.9 billion).
48
52
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
53
13. DECOMMISSIONING OBLIGATION
($000s)
Balance, beginning of year
UGR acquisition (note 4)
Provisions
Decommissioning expenditures
Revisions
Accretion
Balance, end of year
December 31, 2017
29,857
December 31, 2016
21,480
1,093
9,032
—
5,941
888
46,811
—
7,721
(102)
208
550
29,857
The Corporation’s decommissioning obligation results from its ownership interest in petroleum and natural gas
assets including well sites and facilities. The total decommissioning obligation is estimated based on the
Corporation’s net ownership interest in all wells and facilities, estimated costs to reclaim and abandon these
wells and facilities and the estimated timing of the costs to be incurred in future years. The Corporation has
estimated the net present value of the decommissioning obligation based on an undiscounted total future liability
of $106.0 million, compared to $64.2 million at December 31, 2016, with payments expected to be made over
the next 11 to 49 years. The discount factor, being the risk-free rate related to the liability at December 31, 2017,
was 2.3%, compared to 2.1% at December 31, 2016, and the inflation rate was 2% at both December 31, 2017
and 2016.
14. SHARE CAPITAL
(a) Authorized
The Corporation has an unlimited number of Common Shares and Preferred Shares authorized for issuance.
At December 31, 2017, there were 160,995,692 Common Shares outstanding, compared to 100,158,192
Common Shares outstanding at December 31, 2016. At December 31, 2017 and December 31, 2016, there
were no Preferred Shares outstanding.
On April 5, 2017, Painted Pony completed a public offering of 19.8 million Common Shares at a price of
$5.60 per Common Share for aggregate gross proceeds of approximately $111.0 million (including the
exercise in full of the over-allotment option granted to the underwriters).
On May 16, 2017, the Corporation issued 41.0 million Common Shares to acquire all of the issued and
outstanding shares of UGR (see note 4). At the closing date of the UGR acquisition, the Common Shares
were ascribed a fair value of $5.37 per Common Share issued, resulting in total share consideration of $220.2
million (gross of share issue costs).
The Common Shares entitle the holder thereof to one vote for every share held. There are no fixed dividends
payable on the Common Shares. In the event of the liquidation or dissolution of the Corporation, the Common
Shares are entitled to receive, on a pro rata basis, all assets of the Corporation as are distributable to the
holders of shares.
(b) Stock options
The Corporation has a stock option program pursuant to which options to purchase Common Shares are
granted to officers and employees of the Corporation. Stock options are granted at the volume weighted
average trading price of the Common Shares for the five trading days immediately preceding the date of
grant, and have a five-year term. Stock options granted vest as to one-third on each of the first, second and
third anniversaries of the grant date.
49
52
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
53
The number and weighted average exercise prices of stock options are as follows:
As at December 31, 2015
Granted
Exercised
Forfeited
Expired
As at December 31, 2016
Granted
Exercised
Forfeited
Expired
As at December 31, 2017
Weighted Average
Exercise Price ($)
8.26
4.30
5.50
7.23
11.07
7.45
4.42
4.14
10.71
10.16
6.01
Number
8,875,467
1,066,650
(127,250)
(43,350)
(1,149,000)
8,622,517
3,376,650
(17,500)
(179,400)
(1,503,900)
10,298,367
The following table summarizes information about stock options outstanding at December 31, 2017:
Number of
Stock Options
Outstanding
2,037,750
Exercise
Price Range ($)
3.47 - 4.20
Weighted Average
Remaining Life
(Years)
4.0
Number of
Stock Options
Exercisable
311,498
1,837,350
2,199,500
1,811,667
2,412,100
10,298,367
4.21 - 4.28
4.29 - 5.40
5.41 - 8.61
8.62 - 14.14
6.01
2.9
4.4
1.2
1.4
2.8
1,837,350
—
1,700,167
2,412,100
6,261,115
Weighted
Average
Exercise
Price ($)
4.14
4.26
—
6.79
9.72
7.04
The Corporation accounts for its stock options using the fair value method. In accordance with the
Corporation’s incentive stock plan, these stock options have an exercise price equal to the fair value of the
Common Shares at the date of grant.
The weighted-average fair values of the stock options granted and the assumptions used in the Black-
Scholes option pricing model were as follows:
Fair value per stock option ($)
Volatility (%)
Life (years)
Risk-free interest rate (%)
Years ended December 31,
2016
2017
1.86
2.00
50
51
5
5
0.68
1.34
A forfeiture rate of 9% was used when measuring share-based compensation during the year ended
December 31, 2017, compared to 11% during the year ended December 31, 2016.
50
54
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
55
The components of share-based compensation expense (recovery) are presented in the table below:
($000s)
Years ended December 31,
Share-based compensation
Share unit expense (recovery) (note 15)
Total
15. SHARE UNIT PLANS
(a) Deferred Share Units
2017
2,205
(1,724)
481
2016
2,864
2,914
5,778
The Corporation has a DSU plan, whereby DSUs are issued to members of the Board and eligible executive
officers. Each DSU is a notional unit equal in value to one Common Share, which entitles the holder to a
cash payment upon redemption. DSUs vest upon grant but can only be converted to cash upon the holder
ceasing to be a director and/or executive officer of the Corporation. The expense associated with the DSU
plan is determined based on the 20-day volume weighted average price of Common Shares at the grant
date. The expense is recognized in the consolidated statement of operations immediately upon grant, with
a corresponding DSU liability recorded as a current liability in the consolidated statement of financial position.
At period end dates, the DSU liability is adjusted based on the 20-day volume weighted average price of
Common Shares.
The following table summarizes information related to the DSUs:
Deferred share units
Balance, beginning of year
Granted
Accrued but not granted
Prior accrual reversal
Balance, end of year
(b) Restricted Share Units
December 31, 2017
352,689
December 31, 2016
143,337
407,762
—
(70,347)
690,104
139,005
70,347
—
352,689
The Corporation has a RSU plan, whereby RSUs are issued to eligible employees. Each RSU is a notional
unit equal in value to one Common Share, which entitles the holder to a cash payment upon redemption.
RSUs vest in three equal installments on the first, second, and third anniversaries of the grant date, at which
time the holder is eligible to receive a cash payment equal to the number of vested awards multiplied by the
fair market value. The expense associated with the RSU plan is determined based on the 20-day volume
weighted average price of Common Shares at the grant date. The expense is recognized in the consolidated
statement of operations over the vesting period, with a corresponding RSU liability recorded in the
consolidated statement of financial position. At period end dates, the RSU liability is adjusted based on the
20-day volume weighted average price of Common Shares. During the year ended December 31, 2017, the
Company granted 222,630 RSUs. There were no RSUs granted in 2016.
(c) Preferred Share Units
The Corporation has a PSU plan, whereby PSUs are issued to eligible executive officers. Each PSU is a
notional unit equal in value to one Common Share, which entitles the holder to a cash payment upon
redemption. PSUs vest upon the third anniversary of the grant date, at which time the holder is eligible to
receive a cash payment equal to the number of vested awards multiplied by the fair market value. The unit
value is adjusted for a performance multiplier which can range from 0 to 2 and is dependent on the performance
of the Corporation for a predefined period. The expense associated with the PSU plan is determined based
on the 20-day weighted average price of Common Shares at the grant date. The expense is recognized in
51
54
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
55
the consolidated statement of operations over the vesting period, with a corresponding PSU liability recorded
in the consolidated statement of financial position. During the year ended December 31, 2017, the Company
granted 303,900 PSUs. There were no PSUs granted in 2016.
During the year ended December 31, 2017, the Company recorded a recovery of $1.7 million related to the
share unit plans, compared to an expense of $2.9 million for the year ended December 31, 2016. In addition,
$0.3 million was capitalized (2016 - $nil).
16. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
The Corporation’s activities expose it to a variety of financial risks that arise as a result of its exploration,
development, production and financing activities. These include market risk, credit risk and liquidity risk.
The Board oversees management’s establishment and execution of the Corporation’s risk management
framework. Management has implemented and monitors compliance with risk management policies. The
Corporation’s risk management policies are established to identify and analyze the risks faced by the Corporation,
to set appropriate risk limits and controls and to monitor risks and adherence to market conditions and the
Corporation’s activities.
(a) Market risk
Market risk is the risk that changes in market prices, such as commodity prices, foreign exchange rates and
interest rates, will affect the Corporation’s income or the value of the financial instruments. The objective of
market risk management is to manage and control market risk exposures within acceptable parameters,
while optimizing the return.
Natural gas prices obtained by the Corporation are influenced by both US and Canadian supply and demand.
The exchange rate effect cannot be quantified but generally an increase in the value of the Canadian dollar
as compared to the U.S. dollar will reduce the prices received by the Corporation for its petroleum and natural
gas sales. Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of
changes in commodity prices. Commodity prices for petroleum and natural gas are impacted by not only the
relationship between the Canadian and United States dollars, but also upon world political and economic
events that dictate the levels of supply and demand.
The Corporation’s production is usually sold through near term sales contracts with prices fixed at the time
of transfer of custody or on the basis of a monthly average market price. The Corporation, however, may
give consideration in certain circumstances to the appropriateness of entering into long term fixed price
marketing contracts. The majority of the Corporation’s natural gas and NGLs are sold to one purchaser
monthly on a best-efforts basis.
The Corporation uses financial derivatives and physical delivery sales contracts to mitigate some of the
exposure to commodity price risk, and provide a level of stability to operating cash flows which enables the
Corporation to fund its capital development program. The use of these transactions is governed by and is
subject to risk management policies established by the Board.
These instruments are not used for trading or speculative purposes. The Corporation has not designated its
financial derivative contracts as effective accounting hedges, even though the Corporation considers all
commodity contracts to be effective economic hedges. As a result, all such commodity contracts are recorded
at fair value on the consolidated statement of financial position, with changes in the fair value being recognized
as an unrealized gain or loss in the consolidated statement of operations.
Financial assets and liabilities carried at fair value are required to be classified into a hierarchy that prioritizes
the inputs used to measure the fair value. The Corporation’s risk management contracts are valued using
Level 2 inputs. Assets and liabilities in Level 2 are based on valuation models and techniques where the
significant inputs are derived from quoted indices.
52
56
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
57
The following is a summary of all commodity risk management contracts in place as at December 31,
2017.
Financial AECO Natural Gas Contracts
Options traded
AECO Fixed Price Swap
Term
January 2018 - September 2018
AECO Fixed Price Swap
January 2018 - March 2018
AECO Fixed Price Swap
January 2018 - September 2018
AECO Fixed Price Swap
January 2018 - September 2018
AECO Fixed Price Swap
January 2018 - June 2018
AECO Fixed Price Swap
January 2018 - December 2018
AECO Fixed Price Swap
January 2018 - June 2019
AECO Fixed Price Swap
January 2018 - June 2018
AECO Fixed Price Swap
January 2018 - June 2018
AECO Fixed Price Swap
January 2018 - March 2018
AECO Fixed Price Swap
AECO Fixed Price Swap
January 2018 - December 2018
January 2018 - December 2018
AECO Fixed Price Swap
January 2018 - December 2018
AECO Fixed Price Swap
April 2018 - June 2019
AECO Fixed Price Swap
April 2018 - March 2019
AECO Call Option Sold
January 2018 - December 2019
AECO Call Option Sold
January 2018 - December 2019
Volume
(GJ/d)
6,000
10,000
10,000
10,000
6,000
6,000
8,000
10,000
5,000
10,000
10,000
10,000
10,000
10,000
10,000
10,000
15,000
Price
(CDN$/GJ)
3.07
3.18
2.84
2.85
3.03
2.95
2.66
2.88
3.01
3.16
2.57
2.56
2.32
2.62
2.32
2.80
2.93
Financial Dawn Natural Gas Contracts
Options traded
Dawn Fixed Price Swap
Term
April 2018 - March 2019
Dawn Fixed Price Swap
April 2018 - March 2019
Financial NYMEX Basis Differential Contracts
Options traded
NYMEX-AECO Basis Swap
NYMEX-AECO Basis Swap
NYMEX-Dawn Basis Swap
Term
April 2018 - October 2018
April 2019 - September 2021
January 2018 - December 2018
Volume
(GJ/d)
10,000
10,000
Price
(CDN$/GJ)
3.47
3.50
Volume
(MMBtu/d)
10,000
10,000
10,000
Price
(NYMEX less
US$/MMBtu)
1.14
1.14
0.11
56
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
57
53
Financial Station 2 Natural Gas Contracts
Options traded
Stn. 2 Fixed Price Swap
Term
January 2018 - March 2018
Stn. 2 Fixed Price Swap
January 2018 - March 2018
Stn. 2 Fixed Price Swap
January 2018 - March 2018
Stn. 2 Fixed Price Swap
January 2018 - March 2018
Stn. 2 Fixed Price Swap
January 2018 - March 2018
Stn. 2 Fixed Price Swap
January 2018 - March 2018
Stn. 2 Fixed Price Swap
January 2018 - June 2018
Stn. 2 Fixed Price Swap
January 2018 - December 2019
Stn. 2 Fixed Price Swap
April 2018 - June 2019
Stn. 2 Fixed Price Swap
April 2018 - September 2019
Stn. 2 Fixed Price Swap
April 2018 - September 2019
Financial AECO Basis Differential Contracts
Options traded
AECO-Station 2 Basis Swap
Term
November 2018 - October 2020
AECO-Station 2 Basis Swap
November 2018 - October 2020
AECO-Station 2 Basis Swap
November 2018 - August 2021
AECO-Station 2 Basis Swap
November 2019 - October 2020
Financial WTI Crude Oil Contracts
Options traded
WTI Fixed Price Swap
Term
January 2018 - December 2018
WTI Fixed Price Swap
January 2018 - December 2018
WTI Fixed Price Swap
January 2018 - December 2018
WTI Fixed Price Swap
January 2018 - December 2019
WTI Fixed Price Swap
January 2018 - December 2019
Financial Propane Contracts
Options traded
Conway Fixed Price Swap
Conway Fixed Price Swap
Conway Fixed Price Swap
Term
January 2018 - December 2018
January 2018 - December 2018
January 2018 - December 2018
Volume
(GJ/d)
30,000
Price
(CDN$/GJ)
1.78
10,000
15,000
10,000
10,000
15,000
5,000
10,000
12,000
10,000
5,000
1.88
1.74
1.89
1.91
2.70
2.50
2.45
2.35
2.30
2.34
Volume
(GJ/d)
10,000
20,000
20,000
10,000
Price
(AECO less
CDN$/GJ)
0.32
0.32
0.29
0.33
Volume
(Bbl/d)
500
Price
(CDN$/Bbl)
65.15
250
250
500
500
70.15
71.05
70.20
70.20
Volume
(GAL/d)
8,400
10,500
8,400
Price
(CDN$/GAL)
0.90
0.88
1.00
In addition to the commodity risk management contracts discussed above, the Corporation has entered into
physical delivery sales contracts to manage commodity risk. These contracts are considered normal sales
contracts and are not recorded at fair value in the consolidated financial statements.
54
58
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
59
The Corporation has the following foreign exchange risk management contract in place as at December 31,
2017:
Reference
Currency
USD
Notional amount (USD 000s)
$1,000/month
Term
January 2018 - April 2018
Strike Rate
1.3538 CAD/USD
Changes in the price assumptions can have a significant effect on the fair value of the derivative assets and
liabilities and thereby impact income. For financial instruments in place at December 31, 2017, it is estimated
that a $0.10 per mcf change in forward natural gas prices used to calculate the fair value of natural gas
derivatives at December 31, 2017 would result in a $4.9 million change in income for the year ended
December 31, 2017. It is estimated that a $1.00 per bbl change in the forward crude oil prices used to
calculate the fair value of crude oil derivatives at December 31, 2017 would result in a $0.9 million change
in income for the year ended December 31, 2017.
Foreign currency exchange risk is the risk that the fair value of future cash flows will fluctuate as a result of
changes in foreign exchange rates. Substantially all of the Corporation’s petroleum and natural gas sales
are conducted in Canada and are denominated in Canadian dollars, however, Canadian commodity prices
are influenced by fluctuations in the Canadian to U.S. dollar exchange rate. A 1% change in the CAD/US
dollar exchange rate would not result in a material change to income for the year ended December 31, 2017.
Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates.
The Corporation is exposed to interest rate fluctuations on its bank debt which bears a floating rate of interest.
For the year ended December 31, 2017, it is estimated that a 1.0% change in interest rates would result in
a change to income for the year of $1.2 million.
Financial assets and liabilities are presented on a net basis if the Corporation has a legal right to offset and
intends to either settle on a net basis or to realize the asset and settle the liability simultaneously. The
Corporation offsets financial assets and liabilities when the counterparty, currency and timing of settlement
are the same. The following tables provide a summary of the Corporation’s offsetting financial derivative
positions, and how risk management contracts are classified on the consolidated statement of financial
position, respectively.
($000)
Gross in-the-money risk management contracts
Gross out-of-the-money risk management contracts
Net fair value of risk management contracts
December 31, 2017
92,200
(5,479)
86,721
December 31, 2016
1,269
(61,788)
(60,519)
($000)
Current assets
Non-current assets
Current liabilities
Non-current liabilities
Net fair value of risk management contracts
December 31, 2017
65,016
22,552
(553)
(294)
86,721
December 31, 2016
—
1,269
(46,020)
(15,768)
(60,519)
(b) Credit risk
Credit risk is the risk of financial loss to the Corporation if a customer or counterparty to a financial instrument
fails to meet its contractual obligations and arises principally from the Corporation’s receivables from joint
venture partners and petroleum and natural gas purchasers. The Corporation’s maximum exposure to credit
risk at December 31, 2017 and 2016 is as follows:
55
58
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
59
($000)
Accounts receivable
Fair value of risk management contracts
Total
December 31, 2017
39,115
December 31, 2016
29,568
87,568
126,683
1,269
30,837
Accounts receivable
All of the Corporation’s operations are conducted in Canada. The Corporation’s exposure to credit risk is
influenced mainly by the individual characteristics of each customer.
Receivables from petroleum and natural gas purchasers are normally collected on the 25th day of the month
following production. The Corporation’s policy to mitigate credit risk associated with these balances is to
establish marketing relationships with large purchasers. The Corporation historically has not experienced
any collection issues with its petroleum and natural gas purchasers. Receivables from joint venture partners
are typically collected within one to three months of the joint venture bill being issued. The Corporation does
not typically obtain collateral from petroleum and natural gas purchasers or joint venture partners; however,
the Corporation does have the ability to withhold joint venture partners’ share of production from operated
wells in the event of non-payment.
The Corporation does not anticipate any default as it transacts with creditworthy customers and management
does not expect any losses from non-performance by these customers. As such, a provision for doubtful
accounts has not been recorded at either December 31, 2017 or 2016.
The breakdown of accounts receivable at the reporting date by type of customer was:
($000)
Petroleum and natural gas revenue
Financial risk management contracts
Joint interest
Other
Total
December 31, 2017
28,946
December 31, 2016
27,781
7,805
282
2,082
39,115
—
523
1,264
29,568
The Corporation has one primary purchaser of natural gas and NGLs; these purchases accounted for $23.8
million of accounts receivable at December 31, 2017, compared to $23.6 million as at December 31, 2016.
As at December 31, 2017 and 2016, the Corporation’s accounts receivable is aged as follows:
($000)
Less than 30 days
From 31 - 90 days
More than 90 days
Total
December 31, 2017
38,227
December 31, 2016
29,542
771
117
39,115
24
2
29,568
Derivative Financial Instruments
The use of financial swap agreements involves a degree of credit risk that the Corporation manages through
its risk management policies which are designed to limit eligible counterparties to those with investment
grade credit ratings or better.
(c) Liquidity risk
Liquidity risk is the risk that the Corporation will not be able to meet its financial obligations as they become
due. The Corporation’s approach to managing liquidity is to ensure, to the extent possible, that it will always
have sufficient liquidity to meet its liabilities when due, under both normal and stressed conditions, without
incurring unacceptable losses or risking damage to the Corporation’s reputation.
56
60
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
61
Management closely monitors cash flow requirements to ensure that is has sufficient borrowing capacity to
meet operational and financial obligations currently and in the foreseeable future; this excludes the potential
impact of extreme circumstances that cannot reasonably be predicted, such as natural disasters. To achieve
this objective, the Corporation prepares annual capital expenditure budgets, which are regularly monitored
and updated as considered necessary. Further, the Corporation utilizes authority for expenditures on both
operated and non-operated projects to further manage capital expenditures. The Corporation also typically
collects its petroleum and natural gas revenues from most properties on the 25th of each month.
To facilitate the capital expenditure program, the Corporation has an aggregate of $450 million in available
syndicated credit facilities at December 31, 2017 compared to $325 million at December 31, 2016, which
are reviewed semi-annually by its lenders.
(d) Capital management
The Corporation’s policy is to maintain a strong capital base so as to maintain investor, creditor and market
confidence and to sustain future development of the business. The Corporation manages its capital structure
and makes adjustments to it in the light of changes in economic conditions and the risk characteristics of
the underlying petroleum and natural gas assets. The Corporation considers its capital structure to include
shareholders’ equity, loans and borrowings and working capital. In order to maintain or adjust the capital
structure, the Corporation may issue shares or debt and adjust its capital spending to manage current and
projected debt levels.
The Corporation monitors capital based on the total debt to cash flow ratio, on a trailing four fiscal quarter
basis. This ratio is calculated as total debt, defined as outstanding loans and borrowings plus or minus
working capital, excluding fair value of risk management contracts, divided by cash flow from operations
before changes in non-cash working capital and decommissioning expenditures for the most recent calendar
four quarters. In order to facilitate the management of this ratio, the Corporation prepares annual capital
expenditure budgets, which are updated as necessary depending on varying factors including current and
forecast prices, successful capital deployment and general industry conditions. The annual and updated
budgets are approved by the Board of Directors of the Corporation.
As a result of shifting from an exploration-focused program to a development-focused program, the
Corporation has adapted its approach to capital management to include low cost bank debt and introduced
fixed term debt to ensure financial liquidity, as part of the capital structure going forward. Neither the
Corporation nor its subsidiaries is subject to externally imposed capital requirements. The syndicated credit
facilities are subject to a periodic review of the borrowing base which is directly impacted by the value of the
petroleum and natural gas reserves.
17. DETERMINATION OF FAIR VALUES
A number of the Corporation’s accounting policies and disclosures require the determination of fair value, for
both financial and non-financial assets and liabilities. Fair values have been determined for measurement and/
or disclosure purposes based on the following methods. When applicable, further information about the
assumptions made in determining fair values is disclosed in the notes specific to that asset or liability.
(a) Property, Plant and Equipment and Exploration and Evaluation Assets
The fair values of PP&E and E&E assets recognized in an acquisition, are based on market values. The fair
values of PP&E and E&E are the estimated amounts for which they could be exchanged on the acquisition
date between a willing buyer and a willing seller in an arm’s length transaction after proper marketing wherein
the parties had each acted knowledgeably, prudently and without compulsion. The fair value of petroleum
and natural gas interests (included in PP&E) and E&E assets is estimated with reference to the discounted
cash flows expected to be derived from petroleum and natural gas production, based on externally prepared
reserve reports. The risk-adjusted discount rate is specific to the asset with reference to general market
conditions.
57
60
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
61
(b) Accounts Receivable, Accounts Payable and Accrued Liabilities, Bank Debt, Senior Notes and
Convertible Debentures
The fair value of accounts receivable, accounts payable and accrued liabilities, and bank debt are estimated
as the present value of future cash flows, discounted at the market rate of interest at the reporting date. At
December 31, 2017 and December 31, 2016, the fair value of these balances approximated their carrying
value. Bank debt has a floating rate of interest and therefore the carrying value approximates the fair value.
The fair value of the senior notes fluctuates in response to changes in the market rates of interest payable
on similar instruments. At December 31, 2017, the carrying value of the senior notes and convertible
debentures approximated fair value.
(c) Stock Options
The fair value of employee stock options is measured using a Black-Scholes option pricing model.
Measurement inputs include share price on measurement date, exercise price of the instrument, expected
volatility, weighted average expected life of the instruments (based on historical experience and general
stock option holder behavior), expected dividends and the risk-free interest rate.
(d) Derivatives
Measurement
The Corporation classifies the fair value of derivative transactions according to the following hierarchy based
on the amount of observable inputs used to value the instrument.
(i)
(ii)
Level 1: Quoted prices are available in active markets for identical assets or liabilities as of the
reporting date. Active markets are those in which transactions occur in sufficient frequency and
volume to provide pricing information on an ongoing basis.
Level 2: Pricing inputs are other than quoted prices in active markets included in Level 1. Prices are
either directly or indirectly observable as of the reporting date. Level 2 valuations are based on
inputs, including quoted forward prices for commodities, time value and volatility factors, which can
be substantially observed or corroborated in the marketplace.
(iii)
Level 3: Valuations in this level are those with inputs for the asset or liability that are not based on
observable market data.
The fair value of commodity price risk management contracts is determined by discounting the difference
between the contracted prices and published forward price curves as at the date of the consolidated statement
of financial position, using the remaining contracted petroleum and natural gas volumes and risk-free interest
rate (based on published government rates). The fair value of foreign exchange contracts is determined
based on the difference between the contracted forward rate and current forward rates, using the remaining
settlement amount. The Corporation’s commodity price contracts and foreign exchange contracts are valued
using Level 2 of the hierarchy.
The fair value of DSUs, PSUs and RSUs is measured upon grant and at each period end date, using the
20-day volume weighted average price of Common Shares. The Corporation’s DSUs, PSUs and RSUs are
valued using Level 1 of the hierarchy.
18. FINANCE LEASE OBLIGATION
The Corporation is party to a series of agreements relating to the development of processing infrastructure for
natural gas and natural gas liquids. The facilities and related pipeline infrastructure included in these agreements
have been recorded as a finance lease. The Corporation has recorded the asset, with a corresponding obligation
on the consolidated statement of financial position. Over the course of the 20-year lease, there is a capital fee,
which will include finance expense and the amortization of the obligation.
58
62
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
63
The cost of the facilities and related pipeline infrastructure capitalized was $490.9 million. Total expected
payments based on annual take or pay volumes, including both the principal and financing components, are
reflected in the table below.
($000s)
Processing
Transportation
Total
Principal
Within 1 year
52,328
9,880
62,208
3,282
After 1 year but not
more than five years
269,998
53,114
323,112
64,981
More than
five years
579,843
182,355
762,198
422,597
Total
902,169
245,349
1,147,518
490,860
The Corporation has the right to a minimum of 198 MMcf/d of firm capacity at the Townsend Facility, of which
there is a take or pay obligation on production volumes delivered to the facility of 180 MMcf/d. The Corporation
also has the right to the full 99 MMcf/d of firm capacity of the new gas processing train at Townsend, in respect
of which there is a take or pay obligation on production volumes delivered to the facility of 90 MMcf/d commencing
in the first quarter of 2018.
19. COMMITMENTS
($000s)
Transportation and processing
Interest on senior notes
Interest on convertible debentures
Office leases and other
Total commitments
2018
77,704
2019
90,093
2020
99,775
14,399
14,613
2021
98,020
14,765
2022 Thereafter
Total
97,438 1,030,077 1,493,107
67,595
9,576
—
2,438
12,188
3,181
101
96,936 108,958 117,755 115,324 107,021 1,030,077 1,576,071
3,250
117
3,250
1,216
—
—
—
7
14,242
3,250
1,740
Transportation commitments include contracts to transport natural gas and NGLs through third-party owned
pipeline systems in Canada. Processing commitments include contracts to process natural gas through third-
party owned gas processing facilities in British Columbia. Interest on senior notes includes quarterly interest on
senior notes. Interest on convertible debentures includes quarterly interest on convertible debentures. Office
leases include the Corporation’s contractual obligations for office space.
The Corporation has certain lease arrangements that are reflected in the commitments table above, which were
entered into in the normal course of operations. All leases, other than the Townsend Facility finance leases, have
been treated as operating leases whereby the lease payments are included in operating expenses or general
and administrative expenses depending on the nature of the lease.
20. SUPPLEMENTAL DISCLOSURES
(a) Key Management Personnel Compensation
Key management personnel are persons who have the authority and responsibility for planning, directing
and controlling the activities of the Corporation, directly or indirectly. This includes all directors and executives
of the Corporation. Short-term compensation includes salaries, bonuses and short-term benefits paid to
executives and fees paid to directors. Share-based compensation represents amortization of the expense
associated with stock options, PSUs and DSUs granted to executives and directors.
($000)
Short-term compensation
Share-based compensation
Total
December 31, 2017
5,454
379
5,833
December 31, 2016
4,256
4,711
8,967
59
62
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
63
(b) Presentation in Consolidated Statements of Operations
In the Corporation’s consolidated financial statements, items are primarily disclosed by nature except for
employee compensation costs which are included in general and administrative expenses and operating
expenses. In the year ended December 31, 2017, employee compensation costs of $7.0 million were included
in general and administrative expenses, compared to $6.7 million in the year ended December 31, 2016. In
the year ended December 31, 2017 employee compensation costs of $1.1 million were included in operating
expenses, compared to $1.0 million in the year ended December 31, 2016.
(c) Presentation in Consolidated Statements of Cash Flows
Changes in non-cash working capital are comprised of:
($000)
Source/(use) of cash:
Accounts receivable
Prepaid expenses and deposits
Accounts payable and accrued liabilities
Non-cash working capital on business combination
Share unit liability
Operating activities
Investing activities
Financing activities
December 31, 2017 December 31, 2016
(9,547)
(555)
12,028
(2,981)
(1,397)
(2,452)
(2,287)
(4,195)
4,030
(2,452)
(21,394)
467
31,905
—
2,914
13,892
(7,931)
20,609
1,214
13,892
60
64
2018 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
Corporate
Information
BOARD OF DIRECTORS
OFFICERS
Glenn R. Carley
Chairman of the Board
Compensation and HR Committee
Nominating Committee
Governance Committee
Audit and Risk Committee
Patrick R. Ward
President and Chief Executive Officer
Stuart W. Jaggard
Chief Financial Officer
Richard W. Kessy
Chief Operating Officer
Kevin D. Angus
Independent Director
Compensation and HR Committee (Chair)
Edwin S. (Ted) Hanbury
Senior Vice President, Strategic Projects
Paul J. Beitel
Director
Joan E. Dunne
Independent Director
Audit and Risk Committee (Chair)
Reserves and HSE Committee
Nereus L. Joubert
Independent Director
Governance Committee (Chair)
Nominating Committee (Chair)
Compensation and HR Committee
Lynn Kis
Independent Director
Reserves and HSE Committee (Chair)
Audit and Risk Committee
Arthur J. G. Madden
Independent Director
Audit and Risk Committee
Governance Committee
Nominating Committee
George W. Voneiff
Director
Reserves and HSE Committee
Patrick R. Ward
Director
President and Chief Executive Officer
DESIGN: ARTHUR / HUNTER
Tonya L. Fleming
Vice President, General Counsel and Corporate Secretary
L. Barry McNamara
Vice President, Development and Marketing
STOCK EXCHANGE LISTING
The Toronto Stock Exchange
Trading symbol for Common Shares: PONY
AUDITORS
KPMG LLP
BANKERS
The Toronto-Dominion Bank
The Bank of Nova Scotia
Alberta Treasury Branches
Canadian Imperial Bank of Commerce
Royal Bank of Canada
HSBC Bank Canada
Wells Fargo Bank, N.A. Canadian Branch
EVALUATION ENGINEERS
GLJ Petroleum Consultants Ltd.
REGISTRAR AND TRANSFER AGENT
TSX Trust Company
HEAD OFFICE
1800, 736 - 6 Ave SW
Calgary, Alberta T2P 3T7
T 403.475.0440 F 403.238.1487
TOLL FREE 1.866.975.0440
info@paintedpony.ca
E
W www.paintedpony.ca
PAINTED PONY ENERGY LTD.
1800, 736 - 6 Ave SW
Calgary, Alberta T2P 3T7
T
403.475.0440
F
403.238.1487
TOLL FREE 1.866.975.0440
E
info@paintedpony.ca
W www.paintedpony.ca
1
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2017 // PAINTED PONY ENERGY LTD // ANNUAL REPORT
2