P A I N T E D P O N Y P E T R O L E U M L T D .
2 0 1 3 A N N U A L R E P O R T T O S H A R E H O L D E R S
ROCK SOLID
PA I N T E D P O N Y P E T R O L E U M LT D .
CORPORATE PROFILE
Painted Pony Petroleum Ltd. (“Painted Pony” or the “Company”) is a public oil and gas
company based in Calgary Alberta, Canada. Painted Pony's philosophy is to grow
through exploration and development drilling, complemented by strategic
and corporate acquisitions. The Company is primarily focused on
natural gas from the Montney formation in northeast British
Columbia and light oil in southeast Saskatchewan.
Common shares of the Company trade on
the Toronto Stock Exchange under
the symbol “PPY”.
ANNUAL GENERAL MEETING
Painted Pony Petroleum Ltd. invites shareholders and interested parties to attend its Annual General Meeting to be held in the
Harford Room at the Ranchmen's Club, 710 – 13th Avenue SW, Calgary, Alberta on Thursday May 15th, 2014 at 3:00 pm
(Calgary time). Shareholders not attending are encouraged to complete the form of proxy and deliver it in accordance with the
instructions therein at their earliest convenience.
TABLE OF CONTENTS
2 Financial and Operational Highlights
3 Corporate History
5 To Our Shareholders
7 Management's Discussion and Analysis
29 Management's Responsibility for Consolidated Financial Statements
30
Independent Auditors' Report
31 Consolidated Financial Statements
35 Notes to Consolidated Financial Statements
56 Advisory
58 Corporate Information
58 Glossary
1
2013 ANNUAL REPORT TO SHAREHOLDERS
Cover painting "Rock Solid", 50"X40", oil on canvas by Paul Van Ginkel (www.paulvanginkel.com).
PA I N T E D P O N Y P E T R O L E U M LT D .
Financial
($ millions, except per share and shares outstanding)
Petroleum and natural gas revenue
Funds flow from operations
Per share - basic
Per share - diluted
(1)
(2)
(3)
(4)
Net loss
Per share - basic and diluted
(4)
Capital expenditures
Working capital (deficiency)
Bank debt
Total assets
Shares outstanding
Basic weighted-average shares
Fully diluted weighted-average shares
Operational
Daily production volumes
(mcf per day)
Natural gas
Crude oil
(bbls per day)
Natural gas liquids
Total
(boe per day)
Realized prices
Natural gas
Crude oil
Natural gas liquids
Field operating netbacks
British Columbia
Saskatchewan
Company combined
($ per mcf)
($ per bbl)
HIGHLIGHTS
Year ended December 31,
2013
2012
Change
103.1
51.2
0.58
0.58
(5.7)
(0.06)
146.6
(16.3)
28.6
635.1
88,457
88,420
88,488
42,853
1,102
449
8,693
3.45
93.02
62.54
13.96
48.72
18.88
74.8
39.3
0.56
0.55
(48.1)
(0.68)
241.3
45.2
-
612.2
88,052
70,825
70,995
30,248
1,342
206
6,589
2.54
85.67
54.75
9.21
48.00
18.40
38%
30%
4%
5%
88%
91%
4%
-
-
25%
25%
(39%)
(136%)
42%
(18%)
118%
32%
36%
9%
14%
52%
2%
3%
(3)
(5)
(6)
(000s)
(000s)
(000s)
(bbls per day)
($ per bbl)
(7)
($ per boe)
1.
2.
3.
4.
5.
6.
7.
Before royalties
This table contains the term “funds flow from operations”, which should not be considered an alternative to, or more meaningful than “cash flows from
operating activities” as determined in accordance with International Financial Reporting Standards (“IFRS”) as an indicator of the Company's
performance. Funds flow from operations and funds flow from operations per share (basic and diluted) does not have any standardized meaning
prescribed by IFRS and may not be comparable with the calculation of similar measures for other entities. Management uses funds flow from operations
to analyze operating performance and leverage and considers funds flow from operations to be a key measure as it demonstrates the Company's ability to
generate the cash necessary to fund future capital investment. The reconciliation between funds flow from operations and cash flows from operating
activities can be found in “Management's Discussion and Analysis”. Funds flow from operations per share is calculated using the basic and diluted
weighted average number of shares for the period, consistent with the calculations of earnings per share.
Basic per share information is calculated on the basis of the weighted average number of shares outstanding in the period.
Diluted per share information reflects the potential dilutive effect of options.
Including acquisitions, decommissioning obligations, and capitalized share-based payments.
This table contains the term “working capital (deficiency)”. Working capital (deficiency) does not have any standardized meaning prescribed by IFRS and
may not be comparable with the calculation of similar measures for other entities. Management calculates working capital (deficiency) as current assets
less current liabilities and uses this ratio to analyze operating performance and leverage.
This table contains the term “field operating netbacks”. Field operating netback does not have any standardized meaning prescribed by IFRS and may not
be comparable with the calculation of similar measures for other entities. Management calculates field operating netback on a per unit basis as crude oil,
natural gas, natural gas liquids revenues and other income less royalties, operating and transportation costs.
2013 ANNUAL REPORT TO SHAREHOLDERS
2
PA I N T E D P O N Y P E T R O L E U M LT D .
CORPORATE HISTORY
May 17, 2007
July 11, 2007
March 31, 2008
March 16, 2009
February 22, 2010
August 31, 2010
Drilled the
Company's first
Bakken well,
targeting light oil
at Kisbey.
Closed the
Company's initial
public offering for
gross proceeds of
$12 million.
Raised an additional
$1.5 million to satisfy
outstanding debt
obligations.
Acquired producing
natural gas
properties and
undeveloped land in
northeast BC for
$21.2 million, setting
the stage for Painted
Pony's growth in the
Montney.
Drilled first vertical
Montney well on
Cameron property at
a-10-J/94-B-09.
Drilled the
Company's first
operated horizontal
Montney well at the
Blair property.
Drilled the first
middle Montney well
in the region and
consequently
announce a major
Montney discovery.
Drilled the Company's
first Bakken well at
Flat Lake announcing
a major Bakken
discovery.
3
2013 ANNUAL REPORT TO SHAREHOLDERS
PA I N T E D P O N Y P E T R O L E U M LT D .
CORPORATE HISTORY
10,000
9,000
8,000
7,000
6,000
5,000
4,000
3,000
2,000
Production (boe/d)
Production per share
93.03
98.31
3
9
6
,
8
47.22
31.30
70.51
61.17
9
8
5
,
6
1
2
2
,
4
8
4
8
,
2
1,000
3.43
0
25
2
5
5
,
1
1
6
7
07
08
09
10
11
12
13
120
100
80
60
40
20
0
350
300
250
200
150
100
50
0
Reserves (MMboe)
Reserves per share (boe/share)
3.28
3
.
0
9
2
2.17
1.96
1
.
1
9
1
9
.
6
3
1
0.64
0.15
0.15
0.04
4.4
6.5
5
.
2
3
08
09
10
11
12
13
0.6
07
3.50
3.00
2.50
2.00
1.50
1.00
0.50
0
May 25, 2011
September 28, 2011 December 21, 2012
October 17, 2013
December 31, 2013
Drilled and
completed the
Company's first 3
well pad at Blair,
targeting the upper,
middle and lower
Montney zones.
Drilled and completed
Acquired the
Painted Pony
d-44-C/94-B-16 lower
Townsend property
graduated to and
Grew proved plus
probable reserves
Montney well that
for $108 million,
commenced trading
to over 1.7 Tcfe.
tested at
24.5 MMcf/d.
setting the stage for
on the Toronto Stock
liquids rich Montney
Exchange under the
growth.
symbol PPY.
PRODUCTION
RESERVES
2013 ANNUAL REPORT TO SHAREHOLDERS
4
PA I N T E D P O N Y P E T R O L E U M LT D .
TO OUR SHAREHOLDERS
It is with great pleasure and pride that we provide the attached financial and operating results of Painted Pony for 2013. Our
corporate focus over the past year has been to build and strengthen our organization, as we continue to develop one of the finest
natural gas assets in the Western Canada Basin.
The key to our success lies in adhering to four fundamental operating principles:
Maintain status as a low cost producer
In any business, a low cost structure drives profitability. Painted Pony's top tier cost structure is underpinned by the predictable
and repeatable nature of our operations and excellent per well economics. We continuously monitor all of our costs as we keep
a watchful eye on emerging technologies that have the potential to provide step-change improvements in our development
program. Over the past year, we have identified and implemented the open-hole ball-drop completion technique for Montney
horizontal well completions - a new 'first' for the northern Montney fairway in British Columbia. This technology has provided us
with consistent cost savings in excess of $750,000 per well and production increases of over 35% compared to previously used
completion methods. Painted Pony plans to use this completion technique on all of its Montney drilling activity in 2014. We will
continue to refine the ball-drop method and test and develop enhanced completion technology. Production advancements and
cost effective operations remain a cornerstone in Painted Pony's philosophy of growth through the drill bit.
Position the Company to participate in future worldwide natural gas demand growth
Painted Pony is already well positioned for organic and rapid growth within the North American natural gas market. Our
Montney lands are ideally located on important transportation routes, as current and proposed pipeline infrastructure
intersects the Company's properties and provides takeaway capacity to both West Coast and Eastern markets. Readily
accessible natural gas markets in Canada and the United States provide market opportunities for the Company to sell its
products, where we have established a low cost supply. At the same time, we will be well positioned to become a leading
supplier to a possible future global liquefied natural gas (LNG) market. We believe the global LNG market provides a promising
future for the Canadian gas industry and the Company, and we see the future of Canadian natural gas as a premier source of
supply to the global marketplace. We continue to monitor developments in North American supply and demand, and Canadian
West coast LNG export plans directed towards Asian markets. In 2013, we dedicated a significant portion of our $146 million
capital budget to expanding our asset base. We successfully grew our Montney land position during the year from 187 net
sections to 203 net sections, all of which are well positioned within the established British Columbia Montney fairway. Through
our drilling and completions program we grew our year end proved and probable reserves position by 52% to 1.7 trillion cubic
feet of gas equivalent (Tcfe), with additional best estimates of contingent and prospective resources of 7.0 Tcfe and 7.3 Tcfe,
respectively. This large asset base positions Painted Pony to be a leading supplier of natural gas as future North American and
worldwide natural gas demand continues to increase.
Maintain balance sheet flexibility
Painted Pony remains committed to maintaining a conservative and strong balance sheet. The Company has significantly de-
risked the large resource base that exists in our British Columbia Montney fairway, which has allowed the Company to initiate
the use of low cost bank debt in our capital structure as part of the Company's accelerated growth plans. In conjunction with the
conservative utilization of bank debt, we have also initiated a risk management strategy that will assist in providing stable and
predictable cash flow from our natural gas operations. Our hedging position for 2014 currently includes 19.0 MMcf/d of natural
gas per quarter through the first quarter of 2015, at average fixed AECO prices ranging from $3.99/Mcf to $4.18/Mcf, all of
which are above our budget price of $3.71/Mcf. These hedges were implemented at a time when natural gas prices, in the first
quarter of 2014, have been the strongest we have seen in many years.
We can throw stones, complain about them...
We can throw stones, complain about them...
5
2013 ANNUAL REPORT TO SHAREHOLDERS
PA I N T E D P O N Y P E T R O L E U M LT D .
Target production and cash flow growth
During 2013, Painted Pony grew production by 32%, averaging 8,693 boe/d, while natural gas production increased by 42%,
averaging 42.8 MMcf/d, and natural gas liquids production increased by 118% to average 449 bbls/d. We also generated record
funds flow from operations of $51.2 million in a market that has been challenged by low natural gas prices. Painted Pony's 2013
field operating netbacks in British Columbia were $2.33/Mcfe, while the AECO natural gas reference price averaged $3.18/Mcf,
proving that even in the current domestic gas price environment, the Company's operations offer attractive returns. The
Company's corporate strategy has evolved to a focus on the development of its large resource base which will translate into
rapid production and cash flow growth.
In Saskatchewan we continue to explore and develop our light oil assets, as they provide valuable cash flows that can be
redeployed towards further development of the Company's Northeast British Columbia Montney project. Moving forward into
2014, Painted Pony plans to drill 17 net Montney horizontal wells and grow average production by more than 30% to 11,500
boe/d. Our forecast production growth in 2014 and into 2015 will require additional facilities infrastructure. In the first quarter
of 2014, Painted Pony has built a 25 MMcf/d gas dehydration and condensate stabilization facility at Townsend, an area that
has realized significantly higher liquids yields on natural gas production. A further infrastructure expansion is planned at Daiber,
increasing compression and dehydration capacity to 50 MMcf/d from 25 MMcf/d to accommodate the strong production
results from the area. As the Company capitalizes on economies of scale from anticipated future production growth, we are
proactively addressing future infrastructure capacity requirements. Painted Pony is evaluating the feasibility of a 190 MMcf/d
refrigeration plant at Townsend that will leverage off of the successful initiatives already undertaken. This planned facility,
which is expected to be operational in the second half of 2015, will enhance processing capacity in line with expected
production growth. This proactive approach to facility infrastructure allows Painted Pony to position itself to execute its five
year plan that targets production levels to increase to approximately 100,000 boe/d by the end of 2018.
The past success of Painted Pony and the key to our future growth plans revolve around the commitment that our Directors,
Officers and staff have provided the Company. I truly thank them for their efforts over the past year and I look forward to their
continued contributions going into 2014. I would also like to thank our suppliers and Government agencies for their continued
support of our operations. It was with great sadness that the success of 2013 was marked with the sudden passing of Mr. Kelly
Drader, a valued Director of Painted Pony. Kelly's contributions to the Company were significant as he was instrumental in
helping to establish the strategic growth initiatives of the Company. We extend our deepest condolences to Kelly's family as we
recognize that he will be missed by all the employees and Directors of Painted Pony.
Painted Pony's focus over the past year has been on positioning the Company to become a leading British Columbia Montney
natural gas producer, while enhancing the value inherent in the Company's assets for you, our shareholders. As I look back on
our performance in 2013, it is evident that we have executed on and surpassed our goals. Painted Pony delivered exceptional
results in all aspects of its operations including cash flow, production and reserves growth. Our goal for 2014 is to continue to
provide impressive growth to our shareholders through our well established fundamental operating principles.
It is for these reasons that we truly believe 2014 to be 'the year of the Pony with a Rock Solid Future’.
Patrick R. Ward
President and Chief Executive Officer
March 18, 2014
...stumble on them, climb over them,
or build with them. William Ward
or build with them. William Ward
...stumble on them, climb over them,
2013 ANNUAL REPORT TO SHAREHOLDERS
6
PA I N T E D P O N Y P E T R O L E U M LT D .
MANAGEMENT’S DISCUSSION AND ANALYSIS
The following Management's Discussion and Analysis ("MD&A") of the consolidated financial results of Painted Pony
Petroleum Ltd. ("Painted Pony" or the "Company") should be read in conjunction with the consolidated financial statements and
related notes thereto for the years ended December 31, 2013 and December 31, 2012. This commentary is dated March 18,
2014.
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, 2013, are available on SEDAR at www.sedar.com.
DESCRIPTION OF COMPANY
Painted Pony is a Calgary-based exploration and development company primarily focused on natural gas in northeast British
Columbia and light crude oil in southeast Saskatchewan. The Common Shares of Painted Pony trade on the Toronto Stock
Exchange under the symbol "PPY". On October 11, 2013, the Company relocated to a new head office location at 736 - 6th
Avenue S.W., Suite 1800, Calgary, AB.
Painted Pony commenced commercial operations on April 3, 2007 upon completion of a financial reorganization as part of an
overall restructuring of the Company. On May 23, 2007, subsequent to completion of an initial public offering on May 17, 2007,
the Class A shares and Class B shares of Painted Pony began trading on the TSX Venture Exchange. Painted Pony then
commenced an active exploration program. Effective December 1, 2011, the Class B shares of Painted Pony were converted to
Class A shares and, as such, the Class B shares were de-listed from the TSX Venture Exchange. Effective June 7, 2012, the
Class A shares of Painted Pony were re-designated as Common Shares. Effective October 17, 2013, the Common Shares of
Painted Pony began trading on the Toronto Stock Exchange under the symbol "PPY" and were de-listed from the TSX Venture
Exchange.
NON-GAAP MEASURES
This MD&A contains the term "funds flow from operations", which should not be considered an alternative to, or more
meaningful than cash flows from operating activities as determined in accordance with IFRS as an indicator of the Company's
performance. Funds flow from operations and funds flow from operations per share (basic and diluted) do not have any
standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures for other
entities. Management uses funds flow from operations to analyze operating performance and considers funds flow from
operations to be a key measure as it demonstrates the Company's ability to generate the cash necessary to fund future capital
investment and to repay debt. Funds flow from operations per share is calculated using the basic and diluted weighted average
number of shares for the year. The Company reconciles funds flow from operations to cash flows from operating activities,
which is the most directly comparable measure calculated in accordance with IFRS, as follows:
Funds Flow from Operations
($000s)
Cash flows from operating activities
Changes in non-cash working capital
Decommissioning expenditures
Funds flow from operations
Three months ended
December 31,
2012
12,318
17
24
12,359
2013
10,229
1,865
228
12,322
7
2013 ANNUAL REPORT TO SHAREHOLDERS
Year ended
December 31,
2012
39,732
(807)
412
39,337
2013
49,113
1,731
383
51,227
This MD&A also contains other industry benchmarks and terms, such as working capital (deficiency), calculated as current
assets less current liabilities, and field operating netbacks, calculated on a per unit basis as crude oil, natural gas and natural
gas liquids (“NGLs”) revenues and other income, less royalties and operating and transportation costs. These are not
recognized measures under IFRS. Management believes these measures are useful supplemental measures of the net position
of current assets and current liabilities of the Company and the profitability relative to commodity prices. Readers are
cautioned, however, that these measures should not be construed as alternatives to other terms such as current and long-term
debt or comprehensive income determined in accordance with IFRS as measures of performance. Painted Pony's method of
calculating these measures may differ from other companies, and accordingly, may not be comparable to similar measures
used by other companies.
BOE PRESENTATION
A barrel of oil equivalent (“boe”) conversion ratio of six thousand cubic feet of natural gas (“mcf”) to one barrel of oil (“bbl”) (6
mcf:1 bbl) is used as an energy equivalency conversion method primarily applicable at the burner tip and does not represent a
value equivalency at the wellhead. All boe conversions in this report are derived by converting natural gas to crude oil in the
ratio of six mcf of natural gas to one bbl of crude oil. Given that the value ratio based on the current price of crude oil as
compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion ratio of 6:1 may be
misleading as an indication of value.
RESULTS OF OPERATIONS – OVERVIEW
Results of operations for 2013 marked a continued shift in focus for Painted Pony as the Company continues to expand on its
natural gas development plans. Capital expenditures in 2013 were directed towards the delineation and development of the
Company's core Montney natural gas assets in British Columbia, particularly in the Blair and Townsend areas. In 2013, the
Company drilled 13 (9.6 net) wells targeting Montney natural gas. In 2014, the Company plans to drill 18 (17.0 net) Montney
horizontal wells. The advancement of new open-hole ball-drop style completion technology has resulted in production gains
and significantly reduced capital costs on a per-well basis, and has allowed the Company to expand its capital program
accordingly. Peak and final test production rates on wells drilled in the Townsend area during the year exceeded expectations
and required that production volumes be shut in as the Company expands its facility capacity in 2014. At December 31, 2013,
the Company estimates that it had approximately 2,500 boe per day (“boe/d”) of shut-in production, the majority of which is
expected to come on production in the second quarter of 2014.
Capital spending in 2013 included a $9.0 million strategic land acquisition in British Columbia which brings Painted Pony's total
land holdings to approximately 450 net sections, 203 of which are located in the Montney natural gas resource play in British
Columbia.
In 2013, annual daily production volumes increased by 32% to 8,693 boe/d, weighted 82% towards natural gas. These
production gains are attributable to the success of Painted Pony's drilling program, resulting in incremental natural gas and
natural gas liquids production primarily from new Montney horizontal natural gas wells. Key to the Company's continued
success will be necessary facility capacity. To this end, the Company is currently in the process of constructing a 25 million
cubic feet per day (“MMcf/d”) compression and dehydration facility with condensate stabilization at the Company's Townsend
properties, strategically located on the Montney Natural Gas Resource Play. This facility is expected to be completed in the first
quarter of 2014. Further, the Company is directing additional facility capital in 2014 towards the expansion of its Daiber gas
processing facility and the commissioning of an engineering study for a refrigeration and gas plant facility to be built in 2015 to
take advantage of extensive pipeline infrastructure in the area. The Company expects that these improvements will address its
near term facility constraints, with the capability to expand as the production base increases.
PA I N T E D P O N Y P E T R O L E U M LT D .
MANAGEMENT’S DISCUSSION AND ANALYSIS
2013 ANNUAL REPORT TO SHAREHOLDERS
8
PA I N T E D P O N Y P E T R O L E U M LT D .
MANAGEMENT’S DISCUSSION AND ANALYSIS
Natural gas prices in 2013 have rebounded after the significant downward pressure experienced over the previous three years.
The AECO natural gas spot price averaged $3.18 per mcf in 2013, up 33% from 2012. Painted Pony realized a natural gas price in
2013 of $3.45 per mcf, which represents an 8% premium over the AECO price. This premium is a function of the higher heat
content of the Company's natural gas, combined with the differential between AECO pricing and Westcoast Station 2 pricing.
Significant production gains and improved natural gas prices have contributed significantly to higher funds flow from
operations.
Capital activity in 2013 resulted in a reserve evaluation by external reserve evaluators at December 31, 2013 that highlighted a
52% increase in proved plus probable reserves to 290.3 million barrels of oil equivalent (”MMboe”) or 1.74 trillion cubic feet
equivalent, with an associated net present value discounted at 10% of $1.5 billion.
As part of the Company's development focus, it has begun incorporating lower cost bank debt as part of its capital management
strategy. The principal amount utilized under the $125 million available credit facilities at December 31, 2013 was $28.6 million.
Further, in 2013 Painted Pony initiated a natural gas hedging program on up to 19.0 MMcf/d of natural gas production volumes
in order to manage some of the exposure to commodity price risk, and provide a level of stability to operating cash flows which
enables the company to fund its capital development program.
FUNDS FLOW FROM OPERATIONS AND NET LOSS
Painted Pony generated funds flow from operations of $12.3 million during the fourth quarter of 2013, which is consistent with
the comparable quarter in 2012. When comparing the years ended December 31, 2013 and 2012, funds flow from operations
increased 30% to $51.2 million. The increase in funds flow from operations was driven by significant incremental natural gas
production volumes and higher commodity prices, combined with lower royalty expenses. These were partially offset by
higher operating and transportation costs, general and administrative expenses and interest expenses, as well as lower crude
oil production volumes.
The fourth quarter net loss decreased by $36.3 million from $40.7 million in the same period last year primarily due to an
impairment loss of $42.1 in the fourth quarter of 2012.
Painted Pony had a net loss of $5.7 million for the year ended December 31, 2013, compared to $48.1 million during the year
ended December 31, 2012. The net loss in the year ended December 31, 2012 was primarily attributed to an impairment loss of
$42.1 million.
Average Daily Production
Natural gas (mcf/d)
Crude oil (bbls/d)
NGLs (bbls/d)
Total (boe/d)
Three months ended
December 31,
2012 % of total
77
20
3
100
2013 % of total
84
10
6
100
33,430
1,473
244
7,289
46,841
968
537
9,312
Year ended
December 31,
2012 % of total
77
20
3
100
82 30,248
1,342
13
206
5
6,589
100
2013 % of total
42,853
1,102
449
8,693
Fourth quarter production volumes increased 28% compared to the fourth quarter of 2012 to average 9,312 boe/d. These
volumes were weighted 84% towards natural gas. Year over year volumes increased by 32% to average 8,693 boe/d, with a
natural gas weighting of 82% in 2013.
9
2013 ANNUAL REPORT TO SHAREHOLDERS
PA I N T E D P O N Y P E T R O L E U M LT D .
MANAGEMENT’S DISCUSSION AND ANALYSIS
The increase in overall production volumes is the result of a 40% increase in natural gas volumes quarter over quarter and 42%
year over year, reflecting the focus on and success of the natural gas-focused Montney drilling program.
Crude oil volumes for the three months and year ended December 31, 2013 decreased by 34% and 18% compared to the prior
year, reflecting unscheduled facility repairs and maintenance, a third party pipeline failure in Saskatchewan, as well as natural
decline on wells where less capital is being deployed.
Production from NGLs increased in the three months and year ended December 31, 2013 by 120% and 118% compared to the
same period in 2012 due to new production volumes from liquids-rich wells drilled in British Columbia during the year.
The Company anticipates production volumes in 2014 to be increasingly weighted towards natural gas and associated NGLs
targeting the Montney formation in British Columbia. Production is expected to remain flat in the first quarter of 2014, and
increase to approximately 11,500 boe/d for the second quarter of 2014. Overall production in 2014 is expected to average
approximately 11,500 boe/d. The production increase is a direct result of Painted Pony's continued success in its ongoing
development program, as well as the planned commissioning of facilities in the Townsend and Daiber areas which will allow
shut-in production and incremental volumes from 2014 drilling to come on stream.
Petroleum and Natural Gas Revenue
($000s)
Natural gas
Crude oil
NGLs
Other income
Total
Three months ended
December 31,
Year ended
December 31,
2013
16,190
7,733
3,138
392
27,453
2012
10,179
11,314
1,258
164
22,915
2013
54,029
37,409
10,243
1,405
42,093
2012
28,071
4,125
560
103,086
74,849
Petroleum and natural gas revenue was $27.5 million in the three months ended December 31, 2013, 20% higher than the fourth
quarter 2012 reported revenue of $22.9 million as increases in natural gas and NGL revenues more than offset lower crude oil
revenues. Total revenue during the year ended December 31, 2013 was $103.1 million, which represents an increase of 38%
above total revenue in 2012. For the three months ended December 31, 2013, natural gas and NGL revenues increased 59% and
149%. For the year ended December 31, 2013, natural gas and NGL revenues increased 92% and 148%, respectively.
For the three months and year ended December 31, 2013, natural gas revenue comprised 59% and 52% of total revenue,
compared to 44% and 38% in 2012. Revenue growth is consistent with the increase in production over the same periods, and
was even further positively impacted by higher realized commodity prices.
Other income is comprised primarily of third party processing, transportation, salt water disposal and compression fees.
2013 ANNUAL REPORT TO SHAREHOLDERS
10
PA I N T E D P O N Y P E T R O L E U M LT D .
MANAGEMENT’S DISCUSSION AND ANALYSIS
Commodity Prices
Average benchmark prices:
Natural gas
Crude oil
(1)
- Nymex (US$/mmbtu)
- AECO, daily spot ($/mcf)
- WTI (US$/bbl)
- Edmonton par - light oil ($/bbl)
Exchange rate (US$/Cdn$)
Realized commodity prices:
Natural gas ($/mcf)
Crude oil ($/bbl)
NGLs ($/bbl)
Combined ($/boe)
(1) Million British thermal units ("mmbtu")
Three months ended
December 31,
2012
3.54
3.20
88.23
84.51
1.0090
2013
3.85
3.53
97.61
85.70
0.9530
Year ended
December 31,
2012
2.83
2.39
94.14
86.58
1.0000
2013
3.73
3.18
98.05
91.84
0.9710
3.76
86.88
63.47
32.05
3.31
83.49
56.02
34.17
3.45
93.02
62.54
32.49
2.54
85.67
54.75
31.03
For the three months and year ended December 31, 2013, the Company received average natural gas prices that represented
premiums of 7% and 8% to the AECO daily spot prices, respectively. This compares to premiums of 3% and 6% in the
comparative periods. Painted Pony receives a price for its British Columbia natural gas which reflects a higher heat content
than the benchmark, and which varies from the AECO spot price with reference to the British Columbia Westcoast Station 2
reference price. This differential improved throughout 2013 and particularly in the fourth quarter, resulting in premium realized
prices received in these periods.
Realized average crude oil prices for the three months and year ended December 31, 2013 were $86.88 per bbl and $93.02 per
bbl, both of which represent a 1% premium to the Edmonton light reference price. This compares to a 1% discount to the
reference price received in both periods of 2012. Painted Pony's crude oil is a premium light crude oil with low sulfur content.
For the year ended December 31, 2013, approximately 47% of the Company's 2013 NGL volumes are condensate, which
received an average price of $91.73 per bbl, which closely approximates the Edmonton light reference price.
In 2014, the Company expects to receive a natural gas price which will slightly exceed the AECO daily spot price in concert with
Westcoast Station 2 pricing. The Company generally expects to receive an average crude oil price that closely approximates
the Edmonton par reference price, reflecting the prices currently paid for crude oil in Saskatchewan, where the Company
delivers the bulk of its crude oil production. The average prices reported by Painted Pony are reflective of month to month price
and production volume changes.
COMMODITY RISK MANAGEMENT
In 2013 Painted Pony initiated a natural gas hedging program on up to 20,000 gigajoules ("GJ") per day of natural gas production
volumes. The financial risk management program currently uses forward price swaps to manage some of the exposure to
commodity price risk, and provide a level of stability to operating cash flows which enables the company to fund its capital
development program. For the year ended December 31, 2013, Painted Pony had an unrealized gain of $0.1 million on its
commodity risk management contracts.
11
2013 ANNUAL REPORT TO SHAREHOLDERS
PA I N T E D P O N Y P E T R O L E U M LT D .
MANAGEMENT’S DISCUSSION AND ANALYSIS
At December 31, 2013, Painted Pony had entered into the following commodity price contracts:
Natural Gas Financial Swaps
Reference
CDN$ AECO
CDN$ AECO
Volume (GJ/d)
Term
Price ($/GJ)
Option Traded
10,000
10,000
January - December 2014
January - March 2015
3.72
3.90
Swap
Swap
Subsequent to December 31, 2013, Painted Pony entered into additional commodity risk management contracts as outlined in
the table below.
Swap
Swap
Swap
Swap
2012
6,715
2.78
9.0
Natural Gas Financial Swaps
Reference
CDN$ AECO
CDN$ AECO
CDN$ AECO
CDN$ AECO
ROYALTIES
Volume (GJ/d)
Term
Price ($/GJ)
Option Traded
10,000
5,000
5,000
5,000
February - March 2014
April - December 2014
April 2014 - March 2015
January - March 2015
3.90
3.83
3.85
4.21
($000s, except per boe and %)
Royalty expense
Per unit ($ per boe)
Royalties as a % of revenue (%)
Three months ended
Year ended
December 31,
December 31,
2013
1,663
1.94
6.1
2012
1,674
2.50
7.3
2013
6,785
2.14
6.6
For the three months and year ended December 31, 2013, royalties were $1.7 million and $6.8 million, respectively, or
approximately 6.1% and 6.6% of total revenue. For the three months and year ended December 31, 2012, royalties were $1.7
million and $6.7 million, respectively, or 7.3% and 9.0% of revenue. The reduced royalty rate in 2013 was due to higher revenues
in British Columbia which has an average royalty rate for the three months and year ended December 31, 2013 of 2.9% and
2.7%, respectively. Painted Pony's producing properties in British Columbia are on Crown lands and in Saskatchewan are on a
combination of freehold and Crown lands. Royalties include the Saskatchewan resource charge, which totaled $0.2 million
and $0.7 million for both the three months and year ended December 31, 2013 and 2012.
Royalties in both the three months and year ended December 31, 2013 are lower as a percentage of revenue and on a per boe
basis in comparison to the 2012 periods, primarily reflecting the benefit of new liquids-rich wells drilled in British Columbia
which are eligible for royalty holidays, subject to royalty relief of a maximum of $2.2 million per well. Effective April 1, 2013, the
British Columbia provincial government adopted a minimum 3% royalty on production from these wells, and discontinued the
summer drilling grant program.
In 2014, assuming similar commodity prices and reflecting the 3% minimum royalty rate in British Columbia, the Company
anticipates overall royalty rates to be approximately 6% to 7% of total revenues, reflecting the combined impact of incremental
sales volumes from newly drilled wells which will qualify for royalty holidays, net of royalties paid on wells which have obtained
the full benefit of provincial royalty incentives.
2013 ANNUAL REPORT TO SHAREHOLDERS
12
PA I N T E D P O N Y P E T R O L E U M LT D .
MANAGEMENT’S DISCUSSION AND ANALYSIS
OPERATING EXPENSES
Operating expenses ($000s)
Per unit ($ per boe)
Three months ended
December 31,
2012
6,021
8.98
2013
7,893
9.21
Year ended
December 31,
2012
20,121
8.34
2013
29,114
9.17
Operating expenses increased by $1.9 million or $0.23 per boe in the fourth quarter of 2013 and by $9.0 million or $0.83 per boe
for the year ended December 31, 2013 compared to 2012. In British Columbia, these costs increased due to 13th month
adjustments and higher processing facility costs associated with directing liquids-rich production through refrigeration
facilities to increase liquids recoveries. In Saskatchewan, operating costs increased in 2013 due to increased workover and
repair costs as well as fixed costs on a lower production base as the majority of capital is expended in British Columbia. In
addition, an increased percentage of crude oil is being trucked and processed at third party facilities.
During 2014, the Company anticipates that per unit operating costs in British Columbia will benefit from incremental production
volumes. In Saskatchewan, lower repair and maintenance costs are anticipated in 2014, subject to weather-related impacts.
TRANSPORTATION COSTS
Transportation costs ($000s)
Per unit ($ per boe)
Three months ended
December 31,
2012
1,039
1.55
2013
2,241
2.62
Year ended
December 31,
2012
3,643
1.51
2013
7,296
2.30
Transportation costs for the three months and year ended December 31, 2013 were $2.2 million or $2.62 per boe and $7.3
million or $2.30 per boe, respectively. This compares to $1.0 million or $1.55 per boe for the three months ended December 31,
2012 and $3.6 million or $1.51 per boe for the year ended December 31, 2012.
The increased transportation costs are primarily due to increased NGL volumes in British Columbia that came on production in
2013 that have higher transportation costs, as well as fees associated with NGL marketing that will end in the first quarter of
2014, once a Company operated facility is built and operated. In 2014, transportation costs are also expected to decrease with
the commissioning of a new battery in Saskatchewan in the second quarter.
FIELD OPERATING NETBACKS
($/boe)
Revenue
Royalties
Operating expenses
Transportation costs
Field operating netback
Three months ended
December 31,
2012
34.17
(2.50)
(8.98)
(1.55)
21.14
2013
32.05
(1.94)
(9.21)
(2.62)
18.28
Year ended
December 31,
2012
31.03
(2.78)
(8.34)
(1.51)
18.40
2013
32.49
(2.14)
(9.17)
(2.30)
18.88
In the three months ended December 31, 2013, field operating netbacks decreased as a result of higher operating and
transportation costs. The increase in field operating netbacks for the year ended December 31, 2013 compared to 2012 is due
to increased revenues, which were offset by higher operating and transportation costs.
13
2013 ANNUAL REPORT TO SHAREHOLDERS
PA I N T E D P O N Y P E T R O L E U M LT D .
MANAGEMENT’S DISCUSSION AND ANALYSIS
BRITISH COLUMBIA FIELD OPERATING NETBACK
($/boe)
Revenue
Royalties
Operating expenses
Transportation costs
Field operating netback
Three months ended
December 31,
Year ended
December 31,
2013
25.38
(0.72)
(6.75)
(2.69)
15.22
2012
21.01
(0.21)
(5.87)
(1.47)
13.46
2013
23.52
(0.63)
(6.58)
(2.35)
13.96
2012
16.18
(0.11)
(5.46)
(1.40)
9.21
Painted Pony's production volumes from British Columbia in the three months and year ended December 31, 2013 were 8,234
and 7,464 boe/d, respectively, compared with 5,608 boe/d and 5,029 boe/d in 2012, respectively. The increase from
comparable periods was due to incremental production adds from new Montney horizontal gas wells. Natural gas volumes
contributed 95% and 98% of total British Columbia production volumes during 2013 and 2012.
Field operating netbacks improved in British Columbia due to higher natural gas prices, which increased 14% quarter over
quarter and 36% year over year. This increase is partially offset by higher per unit royalty, operating and transportation costs.
During 2013, the Company's field operating netback per unit for British Columbia properties was 59% of revenue per unit,
compared to 57% in 2012.
SASKATCHEWAN FIELD OPERATING NETBACK
($/boe)
Revenue
Royalties
Operating expenses
Transportation costs
Field operating netback
Three months ended
December 31,
Year ended
December 31,
2013
82.95
(11.25)
(27.98)
(2.06)
41.66
2012
78.09
(10.12)
(19.35)
(1.80)
46.82
2013
87.01
(11.34)
(24.97)
(1.98)
48.72
2012
78.90
(11.40)
(17.64)
(1.86)
48.00
Production volumes from Saskatchewan for the three months and year ended were 1,076 and 1,227 boe/d, respectively,
compared with 1,681 boe/d and 1,561 boe/d for the comparable periods in 2012. In Saskatchewan, the primary product is
crude oil, which accounted for 90% of Saskatchewan production volumes in 2013, compared to 86% in 2012. The increased
crude oil weighting in Saskatchewan was due to reduced solution gas production as well as an increased percentage of
volumes being produced from producing properties where natural gas and NGLs are not recovered.
The lower field operating netback in the fourth quarter in Saskatchewan is primarily due to higher operating costs on mature
producing properties. On a year over year basis, the higher field operating netback in Saskatchewan is reflective of a 9%
increase in crude oil prices, partially offset by higher per unit royalties and operating costs. During 2013, Painted Pony's field
operating netback per unit for Saskatchewan properties was 56% of revenue per unit, compared to 61% in 2012.
2013 ANNUAL REPORT TO SHAREHOLDERS
14
PA I N T E D P O N Y P E T R O L E U M LT D .
MANAGEMENT’S DISCUSSION AND ANALYSIS
GENERAL AND ADMINISTRATIVE EXPENSES
($000s, except per boe)
Gross expense
Capitalized
Recoveries
Net expense
Per unit ($ per boe)
Three months ended
December 31,
2012
3,691
(1,259)
(609)
1,823
2.72
2013
5,448
(1,596)
(518)
3,334
3.89
Year ended
December 31,
2012
10,244
(3,312)
(1,899)
5,033
2.09
2013
14,188
(3,737)
(1,787)
8,664
2.73
Net general and administrative (“G&A”) expenses increased by $1.5 million or $1.17 per boe during the three months ended,
and by $3.6 million or $0.64 per boe during the year ended December 31, 2013, compared to the same periods of 2012. G&A
expenses during both periods increased primarily due to salaries, bonuses, consulting costs, an office relocation and
associated administrative costs related to an increase of 23% in the number of employees during the year. Net G&A expenses
for the three months ended December 31, 2013 included bonuses of $1.6 million, net of capitalized bonuses of $1.0 million. Net
G&A expenses for the three months ended December 31, 2012 included bonuses of $0.7 million, net of capitalized bonuses of
$0.5 million.
The Company's policy of allocating and capitalizing costs associated with new capital projects was unchanged in 2013
compared to 2012. During the year ended December 31, 2013, the Company capitalized $3.7 million of administrative costs to
capital projects, compared to $3.3 million during the year ended December 31, 2012. G&A capital and operating recoveries
were in accordance with industry practice and were $1.8 million in the year ended December 31, 2013 compared to $1.9
million in the year ended December 31, 2012.
In 2013, net G&A expenses per boe increased 31% compared to the year ended December 31, 2012, reflecting incremental
staffing and associated costs, while the Company grew average production volumes by 32%. In 2014, with increased
production net G&A expenses are expected to be less than $2.50 per boe.
SHARE-BASED PAYMENTS
($000s)
Gross expense
Capitalized
Net expense
Three months ended
December 31,
2012
3,426
(826)
2,600
2013
2,566
(325)
2,241
Year ended
December 31,
2012
12,824
(3,560)
9,264
2013
9,447
(2,119)
7,328
Gross share-based payments expenses were $2.6 million and $9.4 million for the three months and year ended December 31,
2013 compared to $3.4 million and $12.8 million for the year ended December 31, 2012. The lower expense in both periods is
reflective of reduced costs related to forfeited options, combined with the net effect of the number of options granted at
different exercise prices in each year. The weighted average fair value of stock options granted during 2013 was $3.83 per
option compared to $6.04 per option in 2012.
Share-based payment expense is a non-cash estimate of the cost of granting options to purchase shares, calculated using a
Black-Scholes model. The expense does not represent actual cash compensation realized by the recipients of the options upon
the eventual exercise of these options.
15
2013 ANNUAL REPORT TO SHAREHOLDERS
PA I N T E D P O N Y P E T R O L E U M LT D .
MANAGEMENT’S DISCUSSION AND ANALYSIS
DEPLETION AND DEPRECIATION EXPENSES
Three months ended
Depletion and depreciation ($000s)
Per unit ($ per boe)
December 31,
2013
11,278
13.16
2012
12,030
17.94
Year ended
December 31,
2013
42,422
13.37
2012
39,848
16.52
Depletion and depreciation expense in the three months and year ended December 31, 2013 decreased by $4.78 per boe and
$3.15 per boe, respectively, as compared to the same periods in 2012. The depletion rate was positively impacted by a 52%
increase in total proved and probable reserves at December 31, 2013. At December 31, 2013, future development costs
associated with the development of the Company's proved plus probable reserves were $2.4 billion, compared to $1.5 billion at
December 31, 2012. The increase is associated with probable reserves of 230.4 mboe at December 31, 2013 compared to
148.2 mboe at December 31, 2012.
For the year ended December 31, 2013, Painted Pony excluded exploration and evaluation assets of $72.5 million from the
depletion calculation, compared to $68.7 million for the year ended December 31, 2012.
Depreciation expense was recognized for leasehold improvements, office equipment, computer hardware and software and
office furniture on a 20% per annum declining-balance basis.
EXPLORATION AND EVALUATION
During the three months and year ended December 31, 2013, the Company reported $3.6 million and $5.5 million, respectively,
of exploration and evaluation expense related to non-economic drilling activity and lease expiries primarily in Saskatchewan,
compared to $9.3 million for both the three months and year ended December 31, 2012.
IMPAIRMENT ON PROPERTY, PLANT AND EQUIPMENT
IFRS requires an impairment test to be completed to assess the recoverable value of the property, plant and equipment
("PP&E") within each cash generating unit ("CGU") whenever there is an indication of impairment. The Company currently has
two CGU's, one for British Columbia and one for Saskatchewan. At December 31, 2013 an impairment test was not required for
the British Columbia CGU. At December 31, 2013 as a result of a decreased reserve position compared to December 31, 2012
an impairment test was performed on the Saskatchewan CGU. The recoverable amount of the CGU was based on the higher of
value in use and fair value less costs to sell. The estimate of the fair value less costs to sell was determined using forecasted
cash flows discounted at 10% based on proved plus probable reserves as obtained from the related independent reserve report,
with forecasted prices and future development costs, the independent undeveloped land report, and internally estimated fair
values of facilities. In determining the appropriate discount rate, the Company considered the metrics of recent transactions
completed on assets similar to those in the specific CGU.
2013 ANNUAL REPORT TO SHAREHOLDERS
16
PA I N T E D P O N Y P E T R O L E U M LT D .
MANAGEMENT’S DISCUSSION AND ANALYSIS
The following table outlines the forecasted commodity prices and exchange rates used in the Company's CGU impairment test
as at December 31, 2013. These future prices were based on the forecast commodity prices used by the external reserve
evaluators.
Exchange Rate
(US$ / CAN$)
0.95
0.95
0.95
0.95
0.95
0.95
0.95
0.95
0.95
0.95
0.95
Edmonton Light Oil
(C$/bbl)
92.76
97.37
100.00
100.00
100.00
100.00
100.77
102.78
104.83
106.93
109.07
AECO Gas
(C$/MMBtu)
4.03
4.26
4.50
4.74
4.97
5.21
5.33
5.44
5.55
5.66
5.77
Based on the impairment test completed for Saskatchewan in 2012, it was determined that the net book value of the
Saskatchewan CGU exceeded the recoverable amount and the Company recognized a $42.1 million impairment charge for the
year ended December 31, 2012. At December 31, 2013 the assets in the Saskatchewan CGU were not impaired.
NET FINANCE EXPENSE
Finance charges
Accretion of decommissioning obligations
Interest income
Three months ended
December 31,
2012
51
85
(81)
2013
327
128
(8)
447
Year ended
December 31,
2012
357
313
(546)
2013
960
415
(267)
55 1,108
124
Year
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
Rem.
($000s)
Total
Finance charges include interest expense on bank debt and standby charges on the Company's syndicated credit facilities. For
the three months and year ended December 31, 2013, finance charges were higher than in the comparable period of 2012 as a
result of interest expense on bank debt and from costs related to the 2013 implementation of the syndicated credit facilities.
Accretion costs on decommissioning obligations have increased for the three months and year ended December 31, 2013 as a
result of additional drilled wells, combined with the impact of a higher discount rate used in calculating the present value of the
decommissioning obligation. At December 31, 2013, the risk-free interest rate related to the decommissioning obligations was
increased to 3.1% from 2.4% in 2012.
Interest income for the three months and year ended December 31, 2013 decreased compared to the same periods in 2012,
reflective of reduced levels of cash.
17
2013 ANNUAL REPORT TO SHAREHOLDERS
PA I N T E D P O N Y P E T R O L E U M LT D .
MANAGEMENT’S DISCUSSION AND ANALYSIS
CAPITAL EXPENDITURES
($000s)
Lease acquisitions and retention
Seismic
Drilling and completions
Facilities and equipment
Exploration and evaluation
Exploration and development
Head office expenditures
Capital expenditures
Property acquisitions
Share-based payments
Decommissioning costs
Total expenditures
Three months ended
December 31,
Year ended
December 31,
2013
274
-
19,445
7,533
9,135
36,387
(273)
36,114
20
325
3,247
39,706
202
2013
2012
107 809
585
-
25,073
3,205
17,123
45,508
37
45,545
109,322
827
1,079
824
77,403
28,291
33,061
140,388
2,189
142,577
258
2,119
1,629
-
66,687
17,681
33,135
118,088
489
118,577
115,058
3,560
4,060
156,773
146,583
241,255
During the three months and year ended December 31, 2013, the Company invested $36.4 million and $140.4 million in
exploration and development capital expenditures, compared to $45.5 million and $118.1 million in comparable periods of
2012.
Capital expenditures for the three months ended December 31, 2013 included $19.4 million spent on drilling and completions
activity. The Company drilled 6 (5.5 net) wells in the three month reporting period, including 4 (3.5 net) Montney natural gas
wells in British Columbia and 2 (2.0 net) Bakken crude oil wells in Saskatchewan. Facilities and equipment spending of $7.5
million in the quarter reflects costs related to the design and construction of a 25 MMcf/d gas processing facility. Included in
exploration and evaluation during the quarter was a $9.0 million land acquisition in British Columbia which brought Painted
Pony's total land holdings at December 31, 2013 to 289,770 net acres, compared to 286,874 at December 31, 2012.
Capital expenditures for 2013 were $142.6 million including $77.4 million on drilling and completions. During 2013, the
Company drilled 18 (13.0 net) wells, of which 13 (9.6 net) wells targeted Montney natural gas in British Columbia and 5 (3.4
net) wells targeted crude oil in Saskatchewan. Expenditures on facilities and equipment totaled $28.3 million and included
design and construction costs related to a new gas processing facility, the purchase and installation of a compressor, the
reactivation of a gas gathering system and facility, the installation of pipeline facilities and equipping and tie-in costs.
Exploration and evaluation expenditures included undeveloped land acquisitions at Crown sales totaling $13.8 million,
primarily in British Columbia, as well as drilling and completion costs on projects pending determination of proven and probable
reserves. Drilling and completion costs related to an exploratory well in Saskatchewan were expensed in the first quarter of
2013.
Head office expenditures in the year included $1.8 million of leasehold improvements for new head office space in Calgary as
well as new field offices in British Columbia.
The Company's Board of Directors has approved a $138 million capital exploration and development budget for 2014. The
Company intends to drill a total of 18 (17.0 net) Montney horizontal wells and 3 (1.6 net) Saskatchewan crude oil wells during
the year. Major 2014 facility projects include completion of a 25 MMcf/d gas processing facility, a 25 MMcf/d expansion of a
Company operated facility, and an engineering study for a refrigeration and gas plant facility expected to be constructed in
2015.
2013 ANNUAL REPORT TO SHAREHOLDERS
18
PA I N T E D P O N Y P E T R O L E U M LT D .
MANAGEMENT’S DISCUSSION AND ANALYSIS
RESERVES
Total proved reserves (mboe)
Total proved + probable reserves (mboe)
Per common share outstanding (boe/share)
Net present value discounted at 10% ($ millions)
As at December 31,
2012
42,978
191,143
2.17
1,066
Change
39%
52%
51%
41%
2013
59,878
290,271
3.28
1,502
At December 31, 2013, Painted Pony reported year end proved plus probable reserves of 290.3 MMboe representing an
increase of 52% from December 31, 2012. Associated with proved plus probable reserve additions was a net present value
discounted at 10% of $1.5 billion, which represents a 41% increase over prior year.
Further details of the Company's 2013 year end reserves are provided in the AIF, which is filed under the Company's profile on
SEDAR at www.sedar.com.
LIQUIDITY AND CAPITAL RESOURCES
As at December 31, 2013, the Company had a working capital deficiency of $16.3 million and bank debt of $28.6 million.
Management anticipates that the Company will continue to have adequate liquidity to fund future working capital requirements
and capital expenditures through a combination of cash flows, the availability of credit facilities and investment capital. As a
result of the global economic slowdown, there exists uncertainty in the commodity, credit and capital markets, which the
Company continues to monitor in conjunction with its financing alternatives.
On August 8, 2013, the Company's $100 million demand facility was increased to $125 million syndicated credit facilities from
three Canadian chartered banks with a borrowing base of $125 million, including a $115 million extendible revolving facility and
a $10 million operating facility. The syndicated facilities revolve for a 364 day period plus a one year term-out, which is
extendible annually, subject to syndicate approval. The facilities are subject to a semi-annual borrowing base review, the next
of which is expected to occur on or before May 31, 2014.
The credit facilities bear interest on a matrix system which ranges from bank prime plus 1.0% to bank prime plus 3.5%
depending on the Company's total debt to cash flow ratio as defined by the lender, ranging from less than 1:1 to greater than
3:1. The credit facilities provide that advances may be made by way of prime rate loans, U.S. Base Rate loans, London
InterBank Offered Rate ("LIBOR") loans, bankers' acceptances, letters of credit or letters of guarantee. A standby fee of 0.5% to
0.875% is charged on the undrawn portion of the credit facilities, also calculated depending on the Company's total debt to cash
flow ratio, as defined by the lender. Security is provided by a floating charge demand debenture in the principal amount of $300
million on all of the Company's assets. The Company has provided a negative pledge and undertaking to provide fixed charges
over major producing petroleum and natural gas reserves in certain circumstances.
COMMITMENTS
($000s)
Gas processing
Gas gathering
Oil transportation
Equipment leases
Office leases
2014
4,087
1,631
466
726
1,331
2015
3,773
700
253
618
1,321
2016
3,666
598
90
618
1,093
2017
2,820
-
-
144
1,106
2018
2,467
-
-
-
1,119
Thereafter
6,314
-
-
-
942
Total
23,127
2,929
809
2,106
6,912
19
2013 ANNUAL REPORT TO SHAREHOLDERS
PA I N T E D P O N Y P E T R O L E U M LT D .
MANAGEMENT’S DISCUSSION AND ANALYSIS
Gas processing includes numerous contracts to process natural gas through third party owned gas processing facilities in
British Columbia. Gas gathering includes contracts to transport natural gas through third party owned pipeline systems in
British Columbia. Oil transportation includes contracts requiring minimum tolls for transportation of crude oil through a major
carrier system in Saskatchewan. Equipment leases include agreements to lease compressors related to the construction of
facility infrastructure, expiring in 2016 and 2017. Office leases include the Company's contractual obligations for office space.
SHARE CAPITAL
On December 21, 2012, the Company completed a bought deal financing of 16,997,000 Common Shares at a price of $10.15
per share for total gross proceeds of $172.5 million.
As at December 31, 2013, there were 88,456,760 Common Shares issued and outstanding.
The Company has an incentive stock option plan (the "Plan") whereby options to purchase Common Shares may be granted by
the Board of Directors to directors, officers and employees of, and consultants to, the Company. The Plan has reserved for
issuance a number of Common Shares equal to ten percent of the aggregate number of Common Shares issued and
outstanding from time to time.
During the year ended December 31, 2013, a total of 2,416,500 options were granted at an average exercise price of $7.58.
There were 405,000 options exercised during the year at an average price of $6.06, and 546,000 options forfeited at an average
price of $10.86. During the year ended December 31, 2012, a total of 1,687,800 options were granted at an average exercise
price of $9.38. During 2012 there were also 1,361,733 options exercised at an average price of $4.55 and 132,534 options
forfeited at an average price of $10.55. As at December 31, 2013, 7,826,967 options to purchase Common Shares were issued
and outstanding at a weighted-average price of $8.63 per option for each Common Share. The options are exercisable over a
five year period, with generally one-third vesting immediately, one-third vesting one year from the date of grant, and one-third
vesting two years from the date of grant.
The Company is authorized to issue an unlimited number of Preferred Shares, issuable in series. As at December 31, 2013 and
March 18, 2014, no Preferred Shares were issued or outstanding.
As at March 18, 2014, there were 88,526,260 Common Shares and 7,492,467 options issued and outstanding.
INCOME TAXES
At December 31, 2013, the Company had a $9.4 million deferred income tax asset, compared to $10.1 million as at December
31, 2012. The Company recognized deferred income tax expense of $0.7 million in 2013. For the comparable year, the Company
recognized a deferred income tax recovery of $13.2 million.
As at December 31, 2013, the Company has estimated tax pools of $619.3 million, compared to $526.7 million as at December
31, 2012. The Company expects that future taxable income will be available to utilize accumulated tax pools. Painted Pony's
estimated tax pools at December 31, 2013 are comprised of the following:
2013 ANNUAL REPORT TO SHAREHOLDERS
20
PA I N T E D P O N Y P E T R O L E U M LT D .
MANAGEMENT’S DISCUSSION AND ANALYSIS
Estimated Tax Pools
($000s)
Canadian exploration expense
Canadian development expense
Canadian oil and gas property expense
Undepreciated cost of capital
Non-capital losses
Other
Estimated income tax pools
DIVIDENDS
As at December 31,
2013
80,517
201,404
160,886
79,799
87,626
9,048
619,280
The Company has not declared or paid any dividends and does not intend to do so in the near future.
OFF BALANCE SHEET ARRANGEMENTS
No off balance sheet arrangements existed as at December 31, 2013 or 2012.
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, certain or all of
which may prove to be incorrect. A comparison of actual performance compared to Company announced expectations is as
follows:
Volumes in 2013 were expected to be natural gas weighted. Natural gas constituted 84% and 82% of total production
volumes in the three months and year ended December 31, 2013, respectively.
In 2013, the Company expected to receive a natural gas price equivalent to the AECO daily spot price. The actual weighted
average price received in the fourth quarter and in the year was a 7% and 8% premium, respectively, to this reference
price. Painted Pony's British Columbia natural gas receives a price determined with reference to the British Columbia
Westcoast Station 2 reference price, which received a premium compared to the AECO reference price.
In 2013, the Company expected to receive an average crude oil price approximately 2% less than the Edmonton par
reference price. In the fourth quarter and for the 2013 year, Painted Pony received a weighted average crude oil price 1%
higher than this reference price.
Overall royalties in 2013 were expected to average 6% to 7% of total revenues. Actual royalty rates for the three months
and year ended December 31, 2013 were 6.1% and 6.6%, respectively.
In 2013, per unit operating and transportation costs were expected to be approximately $10.00 per boe. Fourth quarter
2013 operating and transportation expenses were $11.83 per boe, and were $11.47 per boe for the year ended December
31, 2013. The increased cost per unit was primarily due to higher processing fees associated with directing liquids-rich
production through refrigeration facilities to increase liquids recoveries, as well as 13th month adjustments.
21
2013 ANNUAL REPORT TO SHAREHOLDERS
PA I N T E D P O N Y P E T R O L E U M LT D .
MANAGEMENT’S DISCUSSION AND ANALYSIS
CRITICAL ACCOUNTING ESTIMATES
The significant accounting policies used by the Company are disclosed in note 3 of the annual audited consolidated financial
statements for the years ended December 31, 2013 and 2012.
The reader is cautioned that the preparation of financial statements in accordance with IFRS requires management of the
Company to make certain judgments and estimates that affect the reported amounts of assets, liabilities, revenues and
expenses. Estimating reserves is also critical to several accounting estimates and requires judgments and decisions based
upon available geological, geophysical, engineering and economic data. Estimated reserves are also utilized by Painted Pony's
banks in determining credit facilities. Reserves affect net income through depletion, decommissioning obligation estimates
and the impairment test calculation. Estimating reserves is very complex, requiring many judgments based on available
geological, geophysical, engineering and economic data. Changes in these judgments could have a material impact on the
estimated reserves. These estimates may change, having either a negative or positive effect on net earnings as further
information becomes available, and as the economic environment changes. Changes in these judgments and estimates could
have a material impact on the financial results and financial condition of the Company. The MD&A outlines the accounting
policies and practices that are critical to determining Painted Pony's financial results. Certain accounting policies require that
management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the
reported amounts of assets, liabilities and expenses. The Company's management reviews its estimates regularly.
In following the liability method of accounting for income taxes, related assets and liabilities are recognized for the estimated
tax consequences between amounts included in the financial statements and their tax base, using substantively enacted
future income tax rates. Timing of future revenue streams and future capital spending changes can affect the timing of any
temporary differences, and accordingly affect the amount of the future income tax liability calculated at a point in time. These
differences could materially impact earnings.
The Black-Scholes option valuation model was developed for use in estimating the fair value of options, which were fully
tradable with no vesting restrictions. This option valuation model requires the input of assumptions including the expected
stock price volatility. Because the Company's stock options have characteristics significantly different from those of traded
options and because changes in the input assumptions can materially affect the calculated fair value, such value is subject to
measurement uncertainty. With the above risks and uncertainties, the reader is cautioned that future events and results may
vary substantially from that which the Company currently foresees.
NEW STANDARDS AND INTERPRETATIONS NOT YET ADOPTED
The IASB issued amendments to IAS 36, “Impairment of Assets” that require retrospective application and will be effective for
the Company on January 1, 2014. Under the amendments, the recoverable amount is required to be disclosed when an
impairment loss has been recognized or reversed. The adoption of these amendments is not expected to have a material impact
on the Company's consolidated financial statements.
CHANGE IN ACCOUNTING POLICIES
Effective January 1, 2013, the Company adopted new standards with respect to IFRS 10 – “Consolidated Financial
Statements”, IFRS 11 – “Joint Arrangements”, IFRS 12 – “Disclosures of Interests in Other Entities”, as well as the
consequential amendments to IAS 28 – “Investments in Associates and Joint Ventures” (2011), IFRS 13 – “Fair Value
Measurement” and IFRS 7 – “Amendments to Financial Instrument Disclosures”. The adoption of these standards had no
impact on the amounts recorded in the financial statements as at December 31, 2013.
2013 ANNUAL REPORT TO SHAREHOLDERS
22
PA I N T E D P O N Y P E T R O L E U M LT D .
MANAGEMENT’S DISCUSSION AND ANALYSIS
Business Risks, Uncertainties and 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 earnings, expected future
events 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 negative 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 Company'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, but undue reliance should not be placed upon them as they are derived from
numerous assumptions. In addition, forward-looking statements may include statements or information attributable to third
party industry sources. These assumptions are subject to known and unknown risks and uncertainties, including the business
risks discussed in this MD&A, 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. Additionally, there can be no assurance that the plans, intentions or expectations upon which such
forward-looking statements are based will occur.
The 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, certain or all of which may prove to be
incorrect including, but not limited to, the following:
production volumes in 2014 will continue to be increasingly weighted toward natural gas and NGLs targeting the Montney
formation in British Columbia;
the Company will receive a natural gas price which varies in concert with Westcoast Station 2 pricing;
the Company will receive an crude oil price that will vary from the Edmonton par reference price;
overall royalties in 2014 will approximate 6% to 7% of total revenues, assuming similar commodity prices to those realized
in 2013;
average per unit operating and transportation expenses in 2014 are expected to decrease as a result of incremental gas
volumes, as well as lower repair and maintenance costs and reduced treatment and transportation costs in
Saskatchewan, assuming normal seasonal weather conditions;
net G&A expenses are expected to average below $2.50 per boe in 2014;
the 25 MMcf/d gas processing facility being constructed by the Company will be completed in the first quarter of 2014;
the Company has sufficient financial resources with which to conduct its capital program assuming that the drilling rigs,
field service providers, completion and tie-in equipment will be available as required and that the costs of securing such
services and equipment will not materially exceed expectations;
23
2013 ANNUAL REPORT TO SHAREHOLDERS
PA I N T E D P O N Y P E T R O L E U M LT D .
MANAGEMENT’S DISCUSSION AND ANALYSIS
available credit facilities will continue to be utilized in 2014;
commitments to process and transport natural gas through third party owned facilities and pipeline systems in British
Columbia, and commitments to transport crude oil through a major carrier system in Saskatchewan are expected to be
fulfilled;
agreements to lease compressors associated with the construction of facility infrastructure and agreements to lease office
space are expected to be adhered to; and
the risk of accounts receivable becoming uncollectible is mitigated by the financial position of the applicable entities.
Certain or all of the foregoing assumptions may prove to be incorrect and, while it is anticipated that subsequent events and
developments may cause the Company's views to change, there is no intention to update the forward-looking statements,
except as required by applicable securities laws. These forward-looking statements represent the Company's views as of the
date of this MD&A and such information should not be relied upon as representing the Company's views as of any date
subsequent to the date of this MD&A. The Company has attempted to identify important factors that could cause actual results,
performance or achievements to vary from those 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 crude oil 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;
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 Company's ability to attract and retain qualified professional employees and consultants.
2013 ANNUAL REPORT TO SHAREHOLDERS
24
PA I N T E D P O N Y P E T R O L E U M LT D .
MANAGEMENT’S DISCUSSION AND ANALYSIS
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 forward-looking statements 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 Company 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.
In addition to the foregoing risks and assumptions, Painted Pony's production and exploration 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:
The availability of qualified personnel and drilling equipment;
Finding and developing crude oil and natural gas reserves at economic costs;
Production of crude oil and natural gas in commercial quantities; and
Marketability of crude oil and natural gas production.
In order to reduce exploration risk, the Company 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 some exposure to select high-risk plays with high-reward opportunities. Painted
Pony also explores in areas where the Company's officers and employees have significant experience.
The Company mitigates its risk related to producing hydrocarbons through the utilization of the most appropriate technology
and information systems. In addition, Painted Pony seeks operational control of its projects, where feasible.
Oil and gas exploration 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 Company maintains current insurance coverage for general and
comprehensive liability as well as limited pollution liability. 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 of Directors.
LEGAL, ENVIRONMENTAL, REMEDIATION AND OTHER CONTINGENT MATTERS
The Company reviews legal, environmental, remediation and other contingent matters to both determine whether a loss is
probable based on judgment and interpretation of laws and regulations, and determine that the loss can reasonably be
estimated. When the loss is determined, it is charged to earnings. The Company's management monitors known and potential
contingent matters and makes appropriate provisions by charges to earnings when warranted by the circumstances.
25
2013 ANNUAL REPORT TO SHAREHOLDERS
PA I N T E D P O N Y P E T R O L E U M LT D .
MANAGEMENT’S DISCUSSION AND ANALYSIS
DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING
The Company's Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO") have designed, or caused to be designed
under their supervision, disclosure controls and procedures to provide reasonable assurance that: (i) material information
relating to the Company is made known to the Company'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 Company 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. Such officers have evaluated, or caused to be evaluated
under their supervision, the effectiveness of the Company's disclosure controls and procedures at the financial year end of the
Company and have concluded that the Company's disclosure controls and procedures are effective at the financial year end of
the Company for the foregoing purposes.
The Company's CEO and CFO have designed, or caused to be designed under their supervision, internal controls over financial
reporting to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with IFRS. Such officers have evaluated, or caused to be evaluated under their
supervision, the effectiveness of the Company's internal controls over financial reporting at the financial year end of the
Company and concluded that the Company's internal controls over financial reporting are effective, at the financial year end of
the Company, for the foregoing purpose. The Company is required to disclose herein any change in the Company's internal
controls over financial reporting that occurred during the period beginning on October 1, 2013 and ended on December 31,
2013 that has materially affected, or is reasonably likely to materially affect, the Company's internal controls over financial
reporting. No material changes in the Company's internal controls over financial reporting were identified during such period
that have materially affected, or are reasonably likely to materially affect, the Company's internal controls over financial
reporting.
It should be noted that a control system, including the Company'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.
SELECTED CONSOLIDATED QUARTERLY INFORMATION
The following tables set forth selected consolidated financial information of the Company for the eight most recently completed
quarters ending at the fourth quarter of 2013.
Quarter ended
($000s, except volumes and per share)
Petroleum and natural gas revenue
Funds flow from operations
(1)
Basic and diluted, per share
Net income (loss)
Basic and diluted, per share
Cash capital expenditures, net
Capital acquisitions, net
Working capital (deficiency)
Bank debt
Total assets
Decommissioning obligations
Average daily production volumes (boe/d)
(1)
Before royalties and including other income.
Mar. 31,
June 30,
Sept. 30,
Dec. 31,
2013
25,522
14,118
0.16
(1,794)
(0.02)
52,103
-
-
614,714
14,582
8,596
2013
24,644
12,610
0.14
698
0.01
14,871
-
-
595,417
14,351
7,928
9,267
7,324
2013
25,467
12,177
0.14
(209)
(0.00)
39,489
238
(20,657)
-
615,935
13,335
8,925
2013
27,453
12,322
0.14
(4,417)
(0.05)
36,114
20
(16,348)
28,626
635,055
16,482
9,312
2013 ANNUAL REPORT TO SHAREHOLDERS
26
PA I N T E D P O N Y P E T R O L E U M LT D .
MANAGEMENT’S DISCUSSION AND ANALYSIS
Quarter ended
($000s, except volumes and per share)
Petroleum and natural gas revenue
Funds flow from operations
(1)
Basic and diluted, per share
Net loss
Basic and diluted, per share
Cash capital expenditures, net
Capital acquisitions, net
Working capital
Total assets
Decommissioning obligations
Average daily production volumes (boe/d)
(1) Before royalties and including other income.
Mar. 31,
2012
19,665
10,791
0.15
(1,325)
(0.02)
32,310
4,283
42,667
468,693
11,067
6,993
June 30,
2012
15,237
7,695
0.11
(3,523)
(0.05)
10,282
520
42,343
450,606
12,800
5,745
Sept. 30,
2012
17,031
8,492
0.12
(2,594)
(0.04)
30,440
933
20,309
476,260
13,680
6,327
Dec. 31,
2012
22,915
12,359
0.17
(40,669)
(0.56)
45,545
109,322
45,216
612,181
14,821
7,289
SELECTED CONSOLIDATED ANNUAL INFORMATION
The following table sets forth selected consolidated annual financial information of the Company for the three most recently
completed years ending December 31, 2013.
Years ended ($millions, except volumes and per share)
(1)
Petroleum and natural gas revenue
Funds flow from operations
Basic, per share
Diluted, per share
Net income (loss)
Basic and diluted, per share
Cash capital expenditures, net
Capital acquisitions, net
Net working capital (deficiency)
Bank debt
Total assets
Decommissioning obligations
Average daily production volumes (boe/day)
(1)
Before royalties and including other income.
Dec. 31, 2013
103.1
51.2
0.58
0.58
(5.7)
(0.06)
142.6
0.3
(16.3)
28.6
635.1
16.5
8,693
Dec. 31, 2012
74.8
39.3
0.56
0.55
(48.1)
(0.68)
118.6
115.1
45.2
-
612.2
14.8
6,589
Dec. 31, 2011
74.7
44.2
0.74
0.73
6.5
0.11
147.2
8.7
68.3
-
478.7
10.9
4,221
Significant factors and trends that have affected the Company's results during the above annual periods are as follows:
Gross revenues are impacted by both fluctuating commodity prices and production volumes. The Company's successful
capital program has generated incremental production volumes and higher cash flows. The commodity prices realized by
the Company have approximated the Edmonton par light oil prices and AECO daily spot gas 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.
27
2013 ANNUAL REPORT TO SHAREHOLDERS
PA I N T E D P O N Y P E T R O L E U M LT D .
MANAGEMENT’S DISCUSSION AND ANALYSIS
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. Throughout
2011, commodity prices were stronger than in 2012, producing higher funds flow from operations. Throughout 2012,
natural gas and crude oil prices weakened throughout the year, while commodity prices increased in 2013. Royalty
changes vary due to commodity prices, production levels and the status of the different provincial royalty incentive
programs. As the production base matures, incremental royalties occur on wells as the maximum volumes provided for
under the provincial incentive programs are attained.
The net loss in 2013 is primarily attributable to exploration and evaluation, partially offset by higher funds flow from
operations. The 2012 net loss was primarily attributable to a $42.1 million impairment of property, plant as well as
exploration and evaluation expense.
Fluctuations in capital expenditures have reflected both available capital resources and intentional capital spending
restraint during weaker commodity price cycles.
Total assets and non-current liabilities have increased as the Company's capital program is executed.
ADDITIONAL INFORMATION
Additional information regarding the Company and its business and operations is available on the Company's SEDAR profile at
www.sedar.com. Copies of the Company's disclosure can also be obtained by contacting the Company at Painted Pony
Petroleum Ltd., 1800, 736 – 6 Avenue SW., Calgary, Alberta T2P 3T7 (Phone (403) 475-0440), by email at
info@paintedpony.ca or on the Company's website at www.paintedpony.ca.
2013 ANNUAL REPORT TO SHAREHOLDERS
28
PA I N T E D P O N Y P E T R O L E U M LT D .
MANAGEMENT’S RESPONSIBILITY FOR CONSOLIDATED FINANCIAL STATEMENTS
The management of Painted Pony Petroleum Ltd. (the “Company”) 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 Company has established internal accounting control systems which are designed to provide reasonable assurance
regarding the reliability of the Company'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 Committee, monitors management's financial and accounting policies and practices
and the preparation of these consolidated financial statements. The Audit 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 Committee reviews the consolidated financial statements of the Company 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 external auditors have full and free access to the Audit Committee to discuss
auditing and financial reporting matters. The Audit 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 Company, and in that capacity, they have audited the consolidated financial statements for the years ended December
31, 2013 and 2012.
Patrick R. Ward
President and CEO
March 18, 2014
John H. Van de Pol
Vice President, Finance and CFO
2013 ANNUAL REPORT TO SHAREHOLDERS
29
To the Shareholders of Painted Pony Petroleum Ltd.
We have audited the accompanying consolidated financial statements of Painted Pony Petroleum Ltd. which comprise the
consolidated statements of financial position as at December 31, 2013 and December 31, 2012, 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 Petroleum Ltd. as at December 31, 2013 and December 31, 2012, and its consolidated financial performance
and its consolidated cash flows for the years then ended in accordance with International Financial Reporting Standards.
Chartered Accountants
March 18, 2014
Calgary, Canada
PA I N T E D P O N Y P E T R O L E U M LT D .
INDEPENDENT AUDITORS’ REPORT
30
2013 ANNUAL REPORT TO SHAREHOLDERS
PA I N T E D P O N Y P E T R O L E U M LT D .
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
(000s)
As at
ASSETS
Current assets
Cash and cash equivalents
Trade and other receivables
Prepaid expenses and deposits
Fair value of risk management contracts (note 14)
Non-current assets
Fair value of risk management contracts (note 14)
Exploration and evaluation (note 4)
Property, plant and equipment (note 5)
Deferred tax asset (note 12)
LIABILITIES
Current liabilities
Trade and other payables
Non-current liabilities
Bank debt (note 6)
Decommissioning obligations (note 7)
EQUITY
Share capital (note 9)
Contributed surplus
Deficit
Commitments (note 17)
Contingency (note 18)
Subsequent events (note 14)
The notes are an integral part of these consolidated financial statements.
Approved on behalf of the Board:
December 31,
2013
December 31,
2012
$
$
-
16,647
544
42
17,233
77,522
14,427
438
-
92,387
36
72,482
535,862
9,442
635,055
$
-
68,707
441,010
10,077
612,181
$
$
33,581
$
47,171
28,626
16,482
78,689
554,149
44,092
(41,875)
556,366
635,055
-
14,821
61,992
550,116
36,226
(36,153)
550,189
612,181
$
$
Arthur J. G. Madden
Director
Patrick R. Ward
Director
31
2013 ANNUAL REPORT TO SHAREHOLDERS
PA I N T E D P O N Y P E T R O L E U M LT D .
CONSOLIDATED STATEMENTS OF OPERATIONS
2013
2012
$
103,086
$
74,849
(6,785)
96,301
78
96,379
29,114
7,296
8,664
7,328
42,422
5,534
-
100,358
(3,979)
1,375
(267)
1,108
(5,087)
(635)
(5,722)
(6,715)
68,134
-
68,134
20,121
3,643
5,033
9,264
39,848
9,313
42,100
129,322
(61,188)
670
(546)
124
(61,312)
13,201
(000s, except per share amounts)
Years ended December 31,
Revenue
Petroleum and natural gas
Royalties
Unrealized gain on commodity risk management (note 14)
Expenses
Operating
Transportation costs
General and administrative
Share-based payments (note 9)
Depletion and depreciation (note 5)
Exploration and evaluation (note 4)
Impairment of property, plant & equipment (note 13)
Results from operating activities
Finance expense
Finance income
Net finance expense (note 10)
Loss before income tax
Deferred income tax (expense) reduction (note 12)
Net loss and comprehensive loss
$
$
(48,111)
Loss per share (note 8):
Basic and diluted
The notes are an integral part of these consolidated financial statements.
$
(0.06) $
(0.68)
2013 ANNUAL REPORT TO SHAREHOLDERS
32
PA I N T E D P O N Y P E T R O L E U M LT D .
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
Share Contributed Retained earnings/
(Deficit)
capital
$ 11,958
$ 372,792
-
172,520
-
(5,380)
-
-
-
10,184
(48,111)
-
$ 550,116
-
4,033
-
$ 554,149
surplus
$ 27,429
-
-
12,824
(4,027)
-
$ 36,226
9,447
(1,581)
-
$ 44,092
-
-
(5,722)
Total
equity
$ 412,179
172,520
(5,380)
12,824
6,157
(48,111)
9,447
2,452
(5,722)
$ (36,153) $ 550,189
$ (41,875) $ 556,366
(000s, except shares)
Years ended December 31, 2013 and 2012
Balance at December 31, 2011
Issue of shares
Share issue costs, net of tax of $1,851
Share-based payments
Options exercised (note 9)
Net loss for the year
Balance at December 31, 2012
Share-based payments
Options exercised (note 9)
Net loss for the year
Balance at December 31, 2013
Number of
shares
69,693,027
16,997,000
-
-
1,361,733
-
88,051,760
-
405,000
-
88,456,760
The notes are an integral part of these consolidated financial statements.
33
2013 ANNUAL REPORT TO SHAREHOLDERS
PA I N T E D P O N Y P E T R O L E U M LT D .
CONSOLIDATED STATEMENTS OF CASH FLOWS
(000s)
Years ended December 31,
Cash flows from operating activities:
Net loss and comprehensive loss
Adjustments for:
Exploration and evaluation
Share-based payments
Depletion and depreciation
Impairment of property, plant & equipment
Net finance expense
Deferred income tax expense (reduction)
Unrealized gain on commodity risk management
Decommissioning expenditures
Changes in non-cash working capital
Cash flows from investing activities:
Exploration and evaluation additions
Property, plant and equipment additions
Acquisition of property, plant and equipment (note 5)
Changes in non-cash working capital
Cash flows from financing activities:
Issue of share capital
Share issuance costs
Increase in bank debt
Exercise of share options
Net cash finance income (expense)
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
The notes are an integral part of these consolidated financial statements.
2013
2012
$
(5,722)
$
(48,111)
5,534
7,328
42,422
-
1,108
635
(78)
(383)
(1,731)
49,113
(33,061)
(109,516)
(258)
(13,935)
(156,770)
-
-
28,626
2,452
(693)
(250)
30,135
(77,522)
77,522
9,313
9,264
39,848
42,100
124
-
(412)
807
39,732
(13,201)
(33,135)
(85,442)
(115,058)
2,628
(231,007)
172,520
(7,231)
-
6,157
189
192
171,827
(19,448)
96,970
$
-
$
77,522
2013 ANNUAL REPORT TO SHAREHOLDERS
34
PA I N T E D P O N Y P E T R O L E U M LT D .
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As at and for the years ended December 31, 2013 and 2012
1. REPORTING ENTITY
Painted Pony Petroleum Ltd.'s (“Painted Pony” or the “Company”) principal business activity is the exploration, development
and production of petroleum and natural gas resources in Western Canada. The consolidated financial statements of the
Company as at and for the years ended December 31, 2013 and 2012 include the accounts of the Company and its wholly
owned subsidiary, Painted Rock Resources Ltd. The Company's head office is located at 736 – 6th Avenue S.W., Suite 1800,
Calgary, Alberta.
2. BASIS OF PRESENTATION
(a) Statement of Compliance
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 Company on March 18,
2014.
(b) Basis of Measurement
The consolidated financial statements have been prepared on the historical cost basis except for derivative financial
instruments which are measured at fair value. The methods used to measure fair value are discussed in note 15.
(c) Functional and Presentation Currency
These consolidated financial statements are presented in Canadian dollars, which is the Company's and its subsidiary's
functional currency.
(d) Prior Period Comparatives
Prior periods have been restated to conform to presentation in the current period.
(e) Use of Judgments and Estimates
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 changed and in any applicable future periods.
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.
(i) Cash Generating Units (“CGU” or “CGUs”)
The Company's assets are aggregated into cash-generating units 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.
35
2013 ANNUAL REPORT TO SHAREHOLDERS
PA I N T E D P O N Y P E T R O L E U M LT D .
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As at and for the years ended December 31, 2013 and 2012
(ii) Impairment
Judgments are required to assess when impairment indicators exist and impairment testing is required. 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 crude oil and natural gas prices, future costs, discount rates, market value of land and other relevant
assumptions.
The application of the Company's accounting policy for exploration and evaluation assets requires management to make
certain judgments as to future events and circumstances as to whether economic quantities of reserves have been found.
(iii) Taxes
In determining its deferred tax provisions, the Company 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 income tax assets at the end of
the reporting period will be realized from future taxable earnings.
Critical Accounting Estimates
The following are key estimates and their assumptions made by management affecting the measurement of balances and
transactions in these consolidated financial statements.
(i) Impact of Reserves
Estimation of recoverable quantities of proven and probable reserves includes estimates and assumptions regarding future
commodity prices, exchange rates, discount rates and production and transportation cost 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 obligations, the economic feasibility of
exploration and evaluation assets and the amounts reported for depletion, depreciation and amortization 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 Company to establish reserve determinations in accordance with National Instrument 51-
101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”).
The Company estimates the decommissioning obligations for crude oil and natural gas wells and their associated
production facilities and pipelines. In most instances, removal of assets and remediation occurs many years into the future.
Amounts recorded for the decommissioning obligations and related accretion expense require assumptions regarding
removal date, future environmental legislation, the extent of reclamation activities required, the engineering methodology
for estimating cost, inflation estimates, future removal technologies in determining the removal cost, and the estimate of
the liability specific discount rates to determine the present value of these cash flows.
In a business combination, management makes estimates of the fair value of assets acquired and liabilities assumed which
includes assessing the value of crude oil and natural gas properties based upon the estimation of recoverable quantities of
proven and probable reserves being acquired.
2013 ANNUAL REPORT TO SHAREHOLDERS
36
PA I N T E D P O N Y P E T R O L E U M LT D .
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As at and for the years ended December 31, 2013 and 2012
(ii) Share-Based Compensation
The Company's estimate of share-based compensation is dependent upon estimates of historic volatility, risk-free interest
rates and forfeiture rates.
(iii) Derivative Financial Instruments
The Company's estimate of the fair value of any derivative financial instruments is dependent on estimated forward prices
and volatility in those prices.
(iv) Taxes
The deferred tax asset is based on estimates as to the timing of the reversal of temporary differences, substantively
enacted tax rates and the likelihood of assets being realized.
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 Company and its subsidiary.
(a) Basis of Consolidation
Subsidiaries
Subsidiaries are entities controlled by the Company. Control exists when the Company 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.
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 statement of operations.
Jointly Controlled Operations and Jointly Controlled Assets
Most of the Company's crude oil and natural gas activities involve jointly controlled assets. The consolidated financial
statements include the Company'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.
37
2013 ANNUAL REPORT TO SHAREHOLDERS
PA I N T E D P O N Y P E T R O L E U M LT D .
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As at and for the years ended December 31, 2013 and 2012
(b) Financial Instruments
Non-derivative Financial Instruments
Non-derivative financial instruments comprise cash and cash equivalents, trade and other receivables, trade and other
payables and bank debt. 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.
Cash and cash equivalents comprise cash on hand, term deposits held with banks, other short-term highly liquid investments
with original maturities of three months or less. Bank overdrafts that are repayable on demand form part of the Company's cash
management whereby management has the ability and intent to net bank overdrafts against cash, and are included as a
component of cash and cash equivalents, for the purpose of the statement of cash flows.
Other non-derivative financial instruments include trade and other receivables, trade and other payables and bank debt. Trade
and other receivables are measured using the effective interest rate method, less any impairment losses. Trade and other
payables are initially recognized at the amount required to be paid less any required discount to reduce the payables to fair
value. Bank debt is recognized initially at fair value, net of any transaction costs incurred, and subsequently at amortized cost
using the effective interest method.
Derivative Financial Instruments
The Company has entered into certain financial derivative contracts in order to manage the exposure to market risks from
fluctuations in commodity prices. These instruments are not used for trading or speculative purposes. The Company has not
designated its financial derivative contracts as effective accounting hedges and, therefore, has not applied hedge accounting,
even though the Company considers all commodity contracts to be economic hedges. As a result, all financial derivative
contracts are classified as fair value through profit or loss and are recorded on the statements of financial position at fair value.
Transaction costs are recognized in net income when incurred.
(c) Exploration and Evaluation Assets and Property, Plant and Equipment
Recognition and Measurement
(i) Exploration and Evaluation
Pre-licence costs are expensed as incurred. Exploration and evaluation (“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
proven or probable reserves are determined to exist. A review is carried out, on a quarterly basis, to ascertain whether
proven or probable reserves have been discovered. Upon determination of proven 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 assets.
2013 ANNUAL REPORT TO SHAREHOLDERS
38
PA I N T E D P O N Y P E T R O L E U M LT D .
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As at and for the years ended December 31, 2013 and 2012
(ii) Property, Plant and Equipment
Items of PP&E, which include crude oil and natural gas development and production 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 property, plant and equipment, including
crude oil and natural gas interests, have different useful lives, they are accounted for as separate items.
Gains and losses on disposal of an item of PP&E, are determined by comparing the proceeds from disposal, or fair value or
properties received, with the carrying amount of the asset(s) and are recognized in earnings.
Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing
parts of PP&E are recognized as crude oil 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 comprehensive income or
loss as incurred. Such capitalized crude oil and natural gas interests generally represent costs incurred in developing
proven 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 earnings.
Depletion and Depreciation
The net carrying value of development or production assets is depleted using the unit of production method by reference to the
ratio of production in the period to the related proven 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 minimum.
Proven and probable reserves are estimated using independent reserve engineer reports in accordance with NI 51-101 and
represent the estimated quantities of crude oil, 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 proven and probable and a 50 percent statistical probability
that it will be less. The equivalent statistical probabilities for the proven component of proven and probable reserves 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 crude oil 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 primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All boe conversions
in the reserve reports are derived by converting natural gas to crude oil in the ratio of six mcf of gas to one barrel of crude oil.
39
2013 ANNUAL REPORT TO SHAREHOLDERS
PA I N T E D P O N Y P E T R O L E U M LT D .
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As at and for the years ended December 31, 2013 and 2012
Reserves may only be considered proven and probable if producibility is supported by either actual production or a conclusive
formation test. The area of reservoir considered proven includes (a) that portion delineated by drilling and defined by gas-oil
and/or oil-water contacts, if any, or both, and (b) the immediately adjoining portions not yet drilled, but which can be reasonably
judged as economically productive on the basis of available geophysical, geological and engineering data. In the absence of
information on fluid contacts, the lowest known structural occurrence of crude oil and natural gas controls the lower proved
limit of the reservoir.
Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection)
are only included in the proven and probable classification when successful testing by a pilot project, the operation of an
installed program in the reservoir or other reasonable evidence (such as experience of the same techniques on similar
reservoirs or reservoir simulation studies) provides support for the engineering analysis on which the project or program was
based.
For other assets, depreciation is recognized in comprehensive income or loss on a declining-balance rate of 20% based on their
estimated useful lives. Exploration and evaluation 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.
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 earnings.
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 earnings.
Non-financial Assets
The carrying amounts of the Company's non-financial assets, other than exploration and evaluation 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 to sell.
2013 ANNUAL REPORT TO SHAREHOLDERS
40
PA I N T E D P O N Y P E T R O L E U M LT D .
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As at and for the years ended December 31, 2013 and 2012
In assessing fair value less costs to sell, the estimated future cash flows are discounted to their present value using a pre-tax
discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. Fair value
less costs to sell is generally computed by reference to the present value of the future cash flows expected to be derived from
production of proven and probable reserves.
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 earnings. 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 or amortization, if no impairment loss had
been recognized.
(e) Leased Assets
Payments made under operating leases are recognized in comprehensive 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.
(f) Share Capital
Common Shares are classified as equity. Incremental costs directly attributable to the issue of shares and share options are
recognized as a deduction from equity, net of any tax effects.
(g) Share-Based Payments
The Company has issued options to acquire Common Shares to directors, officers and employees. The fair value of options on
the date they are granted is recognized as compensation expense with a corresponding increase in contributed surplus over
the vesting period. A forfeiture rate is estimated on the grant date and is adjusted to reflect the actual number of options that
vest. The Company uses the Black-Scholes model to estimate fair value.
(h) Provisions
A provision is recognized if, as a result of a past event, the Company 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 Obligations
The Company'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.
41
2013 ANNUAL REPORT TO SHAREHOLDERS
PA I N T E D P O N Y P E T R O L E U M LT D .
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As at and for the years ended December 31, 2013 and 2012
Decommissioning obligations are 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 cost whereas increases/decreases due to
changes in the estimated future cash flows are capitalized. Actual costs incurred upon settlement of the decommissioning
obligations are charged against the provision to the extent the provision had been established.
(i) Revenue Recognition
Revenue from the sale of crude oil 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.
Tariffs and tolls charged to other entities for use of pipelines and facilities owned by the Company are recognized as revenue as
they accrue in accordance with the terms of the service or tariff and tolling agreements.
Royalty income is recognized in petroleum and natural gas revenues as it accrues in accordance with the terms of the
overriding royalty agreements.
(j) Finance Income and Expenses
Finance expense consists of interest expense and standby fees on credit facilities, costs related to the implementation of the
credit facilities and accretion on the decommissioning obligation.
Finance income comprises interest income and is recognized as it accrues using the effective interest rate.
(k) Income Tax
Income tax expense comprises deferred income tax expense and is recognized in earnings 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,
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 probable that future taxable profits 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 probable that the related tax benefit will be realized.
(l) Foreign Currency Translation
The principal currency of the economic environment in which the Company and its wholly owned subsidiary 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, with the resulting gain or loss recognized in earnings. Revenues and expenses
are translated into Canadian dollars at average exchange rates. All translation gains and losses are recorded to earnings.
2013 ANNUAL REPORT TO SHAREHOLDERS
42
PA I N T E D P O N Y P E T R O L E U M LT D .
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As at and for the years ended December 31, 2013 and 2012
(m) Earnings (loss) per Share
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 options.
Anti-dilutive instruments are not included in the determination of diluted per share amounts.
(n) Future Accounting Pronouncements
The IASB issued amendments to IAS 36, "Impairment of Assets" that require retrospective application and will be effective for
the Company on January 1, 2014. Under the amendments, the recoverable amount is required to be disclosed when an
impairment loss has been recognized or reversed. The adoption of these amendments is not expected to have a material impact
on the Company's consolidated financial statements.
(o) Change in Accounting Policies
Effective January 1, 2013, the Company adopted new standards with respect to IFRS 10 - "Consolidated Financial Statements",
IFRS 11 - "Joint Arrangements", IFRS 12 - "Disclosures of Interests in Other Entities", as well as the consequential amendments
to IAS 28 - "Investments in Associates and Joint Ventures" (2011), IFRS 13 - "Fair Value Measurement" and IFRS 7 -
"Amendments to Financial Instrument Disclosures". The adoption of these standards had no impact on the amounts recorded in
the financial statements as at December 31, 2013.
4. EXPLORATION AND EVALUATION
(000s)
Cost:
Balance, December 31, 2011
Additions
Transfers to property, plant and equipment
Expensed
Balance, December 31, 2012
Additions
Transfers to property, plant and equipment
Expensed
Balance, December 31, 2013
$
$
$
61,226
33,135
(16,341)
(9,313)
68,707
33,061
(23,752)
(5,534)
72,482
E&E assets consist of undeveloped lands, unevaluated seismic data and unevaluated drilling and completion costs on the
Company's exploration projects which are pending the determination of proven or probable reserves. Additions represent the
Company's share of costs incurred on E&E assets during the year. Transfers are made to PP&E as proven or probable reserves
are determined. E&E assets are expensed due to non-economic drilling and completion activities and lease expiries.
The Company assesses the recoverability of E&E assets as the transfer to PP&E is considered.
43
2013 ANNUAL REPORT TO SHAREHOLDERS
PA I N T E D P O N Y P E T R O L E U M LT D .
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As at and for the years ended December 31, 2013 and 2012
$
Total
352,109
115,058
85,442
7,620
16,341
576,570
258
109,516
3,748
23,752
$
713,844
$
53,612
39,848
42,100
135,560
42,422
177,982
$
$
$
441,010
535,862
5. PROPERTY, PLANT AND EQUIPMENT
(000s)
Cost:
Balance, December 31, 2011
Acquisitions
Cash additions
Non-cash additions
Transfers from exploration and evaluation
Balance, December 31, 2012
Acquisitions
Cash additions
Non-cash additions
Transfers from exploration and evaluation
Balance, December 31, 2013
Accumulated depletion and depreciation:
Balance, December 31, 2011
Depletion and depreciation
Impairment
Balance, December 31, 2012
Depletion and depreciation
Balance, December 31, 2013
Carrying amounts:
At December 31, 2012
At December 31, 2013
The calculation of depletion and depreciation for the three months ended December 31, 2013 included estimated future
development costs of $2.4 billion (December 31, 2012 - $1.5 billion) associated with the development of the Company's proved
plus probable reserves.
(a) Capitalized General and Administrative Expense and Share-based Payments
For the years ended December 31, 2013 and 2012, the Company capitalized general and administrative expenses and share-
based payments as follows:
Years ended December 31, (000s)
General and administrative
Share-based payments
Total
$
$
2013
3,737
2,119
5,856
$
3,312
2012
3,560
$
6,872
(b) Property Acquisitions
During the year ended December 31, 2013, the Company completed one minor strategic property acquisition for $0.2 million. In
the year ended December 31, 2012, the Company acquired $115.1 million of assets, including the purchase of certain northeast
British Columbia gas properties for total cash consideration of $112.8 million.
2013 ANNUAL REPORT TO SHAREHOLDERS
44
PA I N T E D P O N Y P E T R O L E U M LT D .
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As at and for the years ended December 31, 2013 and 2012
(c) Other Assets
The total cost associated with office furniture and fixtures at December 31, 2013 was $3.4 million, with accumulated
amortization of $0.8 million. This compares to a cost of $1.2 million as at December 31, 2012, with accumulated amortization of
$0.4 million.
6. BANK DEBT
The Company has syndicated credit facilities from three Canadian chartered banks with a borrowing base of $125 million,
including a $115 million extendible revolving facility and a $10 million operating facility. The facilities revolve for a 364 day
period plus a one year term-out, which is extendible annually, subject to syndicate approval. The facilities are subject to a semi-
annual borrowing base review, the next of which is expected to occur on or before May 31, 2014.
The credit facilities bear interest on a matrix system which ranges from bank prime plus 1.0% to bank prime plus 3.5%
depending on the Company's total debt to cash flow ratio as defined by the lender, ranging from less than 1:1 to greater than
3:1. The credit facilities provide that advances may be made by way of prime rate loans, U.S. Base Rate loans, London
InterBank Offered Rate ("LIBOR") loans, bankers' acceptances, letters of credit or letters of guarantee. A standby fee of 0.5% to
0.875% is charged on the undrawn portion of the credit facilities, also calculated depending on the Company's total debt to cash
flow ratio, as defined by the lender.
Security is provided by a floating charge demand debenture in the principal amount of $300 million on all of the Company's
assets. The Company has provided a negative pledge and undertaking to provide fixed charges over major producing petroleum
and natural gas reserves in certain circumstances.
7. DECOMMISSIONING OBLIGATIONS
Years ended December 31, (000s)
Balance, beginning of year
Provisions
Revisions
Decommissioning expenditures
Accretion
Balance, end of year
$
$
2013
14,821
1,104
525
(383)
415
$
16,482 $
2012
10,860
3,073
987
(412)
313
14,821
The Company's decommissioning obligations result from its ownership interest in crude oil and natural gas assets including
well sites and facilities. The total decommissioning obligation is estimated based on the Company'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 Company has estimated the net present value of the decommissioning obligations based on
an undiscounted total future liability of $36.0 million (2012: $26.3 million) with payments expected to be made over the next 10
to 38 years. The discount factor, being the risk-free rate related to the liability, is 3.1% (2012: 2.4%) and the inflation rate is 2%
(2012: 2%).
45
2013 ANNUAL REPORT TO SHAREHOLDERS
PA I N T E D P O N Y P E T R O L E U M LT D .
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As at and for the years ended December 31, 2013 and 2012
2013
2012
$
(5,722) $
(48,111)
8. NET LOSS PER SHARE
Years ended December 31,
Net loss for the year (000s)
Weighted average common shares - basic and diluted
88,420,058
70,824,894
Net loss per share - basic and diluted
$
(0.06)
$
(0.68)
The average market value of the Company's Common Shares for purposes of determining the dilutive effect of outstanding
stock options was based on quoted market prices for the period. During the years ended December 31, 2013 and 2012, all
options were excluded from the weighted-average diluted share calculation of Common Shares.
9. SHARE CAPITAL
(a) Authorized
The Company has an unlimited number of Common and Preferred Shares authorized for issuance. At December 31, 2013 there
were 88,456,760 Common Shares outstanding, compared to 88,051,760 Common Shares outstanding at December 31, 2012.
At December 31, 2013 at 2012 there were no Preferred Shares outstanding.
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 Company, the Common Shares are entitled to receive, on a
pro rata basis, all assets of the Company as are distributable to the holders of shares.
(b) Stock Options
The Company has an option program that entitles employees, consultants, officers and directors to purchase Common Shares
in the Company. Stock options are granted at the market price of the shares at the date of grant, have a five year term and
generally vest one-third immediately with the balance over two years.
The number and weighted average exercise prices of stock options are as follows:
Balance, December 31, 2011
Granted
Exercised
Forfeited
Balance, December 31, 2012
Granted
Exercised
Forfeited
Balance, December 31, 2013
Weighted Average
Exercise Price
Number
6,167,934
$
$
$
8.00
9.38
4.55
10.55
9.05
7.58
6.06
10.86
8.63
6,361,467
1,687,800
(1,361,733)
(132,534)
2,416,500
(405,000)
(546,000)
7,826,967
2013 ANNUAL REPORT TO SHAREHOLDERS
46
PA I N T E D P O N Y P E T R O L E U M LT D .
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As at and for the years ended December 31, 2013 and 2012
The following table summarizes information about stock options outstanding at December 31, 2013:
Number of options
outstanding
358,500
188,300
332,167
17,000
589,400
1,130,400
354,000
30,000
152,500
684,700
535,900
80,000
423,000
534,600
360,000
364,000
1,692,500
7,826,967
Exercise
price ($)
2.85
3.15
5.88
5.60
6.51
10.60
12.10
11.19
14.15
11.80
7.56
7.10
10.86
10.59
10.33
10.13
6.44
8.63
Remaining
life (yrs)
0.6
0.6
1.0
1.4
1.7
2.3
2.4
2.5
2.6
2.9
3.3
3.4
3.7
3.9
4.0
4.3
5.0
3.1
Exercisable
options
358,500
188,300
332,167
17,000
589,400
1,130,400
354,000
30,000
152,500
684,700
350,866
53,332
282,000
356,400
120,000
121,333
564,166
5,685,064
Exercise
price ($)
2.85
3.15
5.88
5.60
6.51
10.60
12.10
11.19
14.15
11.80
7.56
7.10
10.86
10.59
10.33
10.13
6.44
8.85
The weighted average share price at the date of exercise for share options exercised during the year ended December 31, 2013
was $10.10 (2012: $9.11).
The Company accounts for its stock options granted to employees, consultants, officers and directors using the fair value
method. In accordance with the Company's incentive stock plan, these options have an exercise price equal to the fair value of
the Company's Common Shares at the date of grant.
The weighted-average fair values of the options granted and the assumptions used in the Black-Scholes option pricing model
were as follows:
Years ended December 31,
Fair value per option
Volatility (%)
Option life (years)
Dividends
Risk-free interest rate (%)
$
2013
3.83 $
56
5
-
1.63
2012
6.04
80
5
-
1.65
During the year ended December 31, 2013, 2,416,500 stock options were granted at an average price of $7.58. During the year
ended December 31, 2012, 1,687,800 stock options were granted at an average price of $9.38.
A forfeiture rate of 7% (2012: 3%) was used when measuring share-based payments.
47
2013 ANNUAL REPORT TO SHAREHOLDERS
PA I N T E D P O N Y P E T R O L E U M LT D .
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As at and for the years ended December 31, 2013 and 2012
10. NET FINANCE EXPENSE
Years ended December 31, (000s)
Finance expense:
Interest and financing costs
Accretion of decommissioning obligations
Finance income:
Interest income
Net finance expense
11. SUPPLEMENTAL CASH FLOW INFORMATION
Changes in non-cash working capital is comprised of:
Years ended December 31, (000s)
Source/(use) of cash:
Trade and other receivables
Prepaid expenses and deposits
Trade and other payables
12. DEFERRED INCOME TAX
Reconciliation of effective tax rate:
Years ended December 31, (000s)
Loss before income tax
Combined corporate tax rate
Expected income tax expense (reduction)
Non-deductible expenses
Share-based compensation
Change in statutory tax rates
Total income tax expense (reduction)
Years ended December 31, (000s)
Deferred tax liabilities:
PP&E and E&E assets
Fair value of financial instruments
Less deferred tax assets:
Provisions
Share issue costs
Non-capital losses
Net deferred tax asset
Deferred tax assets and liabilities are attributable to the following:
$
$
2013
960
415
1,375
2012
357
313
670
(267)
(546)
$
1,108 $
124
2013
(2,220)
(106)
(13,590)
(15,916)
$
$
$
2012
7,041
57
(3,471)
$
3,627
$
(5,087) $
(61,312)
$
(1,302) $
(15,696)
2013
25.6%
22
1,961
(46)
2012
25.6%
2,452
16
27
$
635
$
(13,201)
2013
2012
$
(19,500)
$
(5,613)
(20)
(19,520)
4,234
2,240
22,488
9,442
$
$
-
(5,613)
3,794
3,436
8,460
10,077
2013 ANNUAL REPORT TO SHAREHOLDERS
48
PA I N T E D P O N Y P E T R O L E U M LT D .
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As at and for the years ended December 31, 2013 and 2012
The Company has non-capital losses of $87.6 million. Of these losses, 99% expire beginning in the year 2030. Based on a
reserve report prepared by external reservoir evaluators, the Company has determined that it is probable that these losses will
be utilized against future taxable income.
Movement in deferred tax balances during the year:
PP&E
and E&E
$ (12,913)
7,300
-
(5,613)
(13,887)
$ (19,500)
Fair value of
financial
instruments
$ -
-
-
-
(20)
$ (20)
Share
issue
costs
Provisions
$ 2,792
$ 2,927
1,002
-
(1,342)
1,851
3,794
3,436
440
(1,196)
Non-capital
losses
$ 2,219
6,241
-
8,460
14,028
$ 4,234 $ 2,240
$ 22,488
Balance, December 31, 2011
Recognized in comprehensive income
Recognized directly in equity
Balance, December 31, 2012
Recognized in comprehensive income
Balance, December 31, 2013
13. IMPAIRMENT
IFRS requires an impairment test to be completed to assess the recoverable value of the PP&E within each CGU whenever there
is an indication of impairment. The Company currently has two CGU's, one for British Columbia and one for Saskatchewan. At
December 31, 2013 an impairment test was not required for the British Columbia CGU. At December 31, 2013 as a result of a
decreased reserve position compared to December 31, 2012 an impairment test was performed on the Saskatchewan CGU.
The recoverable amount of the CGU was based on the higher of value in use and fair value less costs to sell. The estimate of the
fair value less costs to sell was determined using forecasted cash flows discounted at 10% based on proved plus probable
reserves as obtained from the related independent reserve report, with forecasted prices and future development costs, the
independent undeveloped land report, and internally estimated fair values of facilities. In determining the appropriate discount
rate, the Company considered the metrics of recent transactions completed on assets similar to those in the specific CGU.
The following table outlines the forecasted commodity prices and exchange rates used in the Company's CGU impairment test
as at December 31, 2013. These future prices were based on the forecast commodity prices used by the external reserve
Exchange Rate
Edmonton Light Oil
(US$ / CAN$)
AECO Gas
(C$/MMBtu)
evaluators.
Year
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
Rem.
0.95
0.95
0.95
0.95
0.95
0.95
0.95
0.95
0.95
0.95
0.95
(C$/bbl)
92.76
97.37
100.00
100.00
100.00
100.00
100.77
102.78
104.83
106.93
109.07
4.03
4.26
4.50
4.74
4.97
5.21
5.33
5.44
5.55
5.66
5.77
Based on the impairment test completed for Saskatchewan in 2012, it was determined that the net book value of the
Saskatchewan CGU exceeded the recoverable amount and the Company recognized a $42.1 million impairment charge for the
year ended December 31, 2012. At December 31, 2013 the assets in the Saskatchewan CGU were not impaired.
49
2013 ANNUAL REPORT TO SHAREHOLDERS
PA I N T E D P O N Y P E T R O L E U M LT D .
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As at and for the years ended December 31, 2013 and 2012
14. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
The Company'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 of Directors of the Company oversees management's establishment and execution of the Company's risk
management framework. Management has implemented and monitors compliance with risk management policies. The
Company's risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate
risk limits and controls and to monitor risks and adherence to market conditions and the Company'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 Company'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 Company are influenced by both US and Canadian supply and demand and an anticipated
increased demand for liquefied natural gas. Prices for crude oil are determined in global markets and generally denominated in
United States dollars. 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 Company 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 crude oil and natural gas are impacted by not only the relationship between the Canadian and United
States dollars, but also upon world economic events that dictate the levels of supply and demand.
The Company'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 Company, however, may give consideration in certain circumstances to
the appropriateness of entering into long term fixed price marketing contracts. The Company has contracted the majority of its
crude oil to one purchaser on a month-to-month rolling contract. The majority of the Company's natural gas is sold to one
purchaser monthly on a best-efforts basis.
The Company 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 Company 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 of
At December 31, 2013, the Company has entered into the following commodity price contracts:
Directors of the Company.
Commodity Price Contracts
Natural Gas Financial Swaps
Reference
CDN$ AECO
CDN$ AECO
Total fair value
Volume (GJ/d)
Term
Price ($/GJ)
10,000
10,000
January - December 2014
January - March 2015
3.72
3.90
Option
traded
Swap
Swap
Fair value
(000s)
$ 42
36
$ 78
2013 ANNUAL REPORT TO SHAREHOLDERS
50
PA I N T E D P O N Y P E T R O L E U M LT D .
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As at and for the years ended December 31, 2013 and 2012
Subsequent to December 31, 2013, the Company entered into additional commodity risk management contracts as outlined
Natural Gas Financial Swaps
below:
Reference
CDN$ AECO
CDN$ AECO
CDN$ AECO
CDN$ AECO
Volume (GJ/d)
Term
Price ($/GJ)
10,000
5,000
5,000
5,000
February - March 2014
April - December 2014
April 2014 - March 2015
January - March 2015
Option
traded
Swap
Swap
Swap
Swap
3.90
3.83
3.85
4.21
For the year ended December 31, 2013, if natural gas prices had been US$0.10 per mcf higher, with all other variables held
constant, the net loss for the year would have been $1.6 million lower. An equal and opposite impact would have occurred to
net loss had natural gas prices been US$0.10 per mcf lower. For the year ended December 31, 2013, if crude oil prices had been
US$1 per barrel higher, with all other variables held constant, net loss for the year would have been $0.4 million lower. An equal
and opposite impact would have occurred to net loss had crude oil prices been US$1 per barrel lower.
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 Company'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.
Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The Company is
exposed to interest rate fluctuations on its bank debt which bears a floating rate of interest. In the year ended December 31,
2013, if interest rates had been 0.5% lower with all other variables held constant, net loss for the year would have been $0.1
million lower. An equal and opposite impact would have occurred to net loss had interest rates been 0.5% higher.
(b) Credit Risk:
Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its
contractual obligations and arises principally from the Company's receivables from joint venture partners and crude oil and
natural gas purchasers. The Company's maximum exposure to credit risk at December 31, 2013 and 2012 is as follows:
Carrying amounts, December 31, (000s)
Cash and cash equivalents
Trade and other receivables
Fair value of financial instruments
Total
Cash and cash equivalents:
2013
-
16,647
78
$
77,522
2012
14,427
-
$
16,725
$
91,949
The Company limits its exposure to credit risk by only investing in liquid securities that are guaranteed by the Province of
Alberta. Given these credit ratings, management does not expect any counterparty to fail to meet its obligations.
Trade and other receivables:
All of the Company's operations are conducted in Canada. The Company's exposure to credit risk is influenced mainly by the
individual characteristics of each customer.
51
2013 ANNUAL REPORT TO SHAREHOLDERS
PA I N T E D P O N Y P E T R O L E U M LT D .
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As at and for the years ended December 31, 2013 and 2012
Receivables from crude oil and natural gas purchasers are normally collected on the 25th day of the month following
production. The Company's policy to mitigate credit risk associated with these balances is to establish marketing relationships
with large purchasers. The Company historically has not experienced any collection issues with its crude oil 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 Company attempts to mitigate the risk from joint venture receivables by obtaining partner pre-approval.
However, the receivables are from participants in the oil and gas sector and collection of the outstanding balances is dependent
on industry factors such as commodity price fluctuations, escalating costs and the risk of unsuccessful drilling. In addition,
further risk exists with joint venture partners if a disagreement were to arise, which may increase the potential for non-
collection. The Company does not typically obtain collateral from crude oil and natural gas purchasers or joint venture partners;
however, the Company does have the ability to withhold joint venture partners' share of production from operated wells in the
event of non-payment.
The Company 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, 2013 or 2012.
The breakdown of trade and other receivables at the reporting date by type of customer was:
The Company has two significant independent crude oil and natural gas purchasers. One entity purchases the majority of
natural gas produced in British Columbia, and the second entity purchases the majority of crude oil produced in Saskatchewan.
These purchases accounted for $8.8 million of trade and other receivables at December 31, 2013 (December 31, 2012: $7.2
As at December 31, 2013 and 2012, the Company's trade and other receivables are aged as follows:
$
$
7,720
$
16,647
$
14,427
2013
10,012
3,467
3,168
2013
16,067
308
272
2012
1,943
4,764
2012
731
208
$
$
13,488
$
16,647
$
14,427
Carrying amount, December 31, (000s)
Petroleum and natural gas revenue
Joint interest
Other
Total
million).
Carrying amount, December 31, (000s)
Less than 30 days
From 31 - 90 days
More than 90 days
Total
Derivatives:
The use of financial swap agreements involves a degree of credit risk that Painted Pony 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 Company will not be able to meet its financial obligations as they become due. The Company'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 Company's reputation.
2013 ANNUAL REPORT TO SHAREHOLDERS
52
PA I N T E D P O N Y P E T R O L E U M LT D .
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As at and for the years ended December 31, 2013 and 2012
Management closely monitors cash flow requirements to ensure that is has sufficient cash on demand or 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 Company
prepares annual capital expenditure budgets, which are regularly monitored and updated as considered necessary. Further, the
Company utilizes authority for expenditures on both operated and non-operated projects to further manage capital
expenditures. The Company also typically collects its crude oil and natural gas revenues from most properties on the 25th of
each month.
To facilitate the capital expenditure program, the Company has an aggregate of $125 million in syndicated credit facilities at
December 31, 2013 (2012: $100 million demand facility), which are reviewed semi-annually by its lenders. The principal
amount utilized under the syndicated credit facilities at December 31, 2013 was $28.6 million (2012: $nil).
(d) Capital Management:
The Company'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 Company manages its capital structure and makes adjustments to it in the
light of changes in economic conditions and the risk characteristics of the underlying crude oil and natural gas assets. The
Company considers its capital structure to include shareholders' equity, loans and borrowings and working capital. In order to
maintain or adjust the capital structure, the Company may issue shares and adjust its capital spending to manage current and
projected debt levels.
The Company monitors capital based on the ratio of net debt to annualized cash flow. This ratio is calculated as net debt,
defined as outstanding loans and borrowings plus or minus working capital, divided by cash flow from operations before
changes in non-cash working capital and decommissioning expenditures for the most recent calendar quarter and then
annualized. The Company's objective is to maintain a net debt to annualized cash flow ratio of less than 2:1, with a targeted ratio
of 1.5:1. In order to facilitate the management of this ratio, the Company 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 Company.
As a result of shifting from an exploration-focused program to a development-focused program, the Company has adapted its
approach to capital management to include low cost bank debt as part of the capital structure going forward. Neither the
Company nor its subsidiary 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 crude oil and natural gas reserves.
15. DETERMINATION OF FAIR VALUES
A number of the Company'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) Exploration and Evaluation and Property, Plant and Equipment 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 crude oil and natural gas interests (included in property, plant and
equipment) and exploration and evaluation assets is estimated with reference to the discounted cash flows expected to be
derived from crude oil 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.
53
2013 ANNUAL REPORT TO SHAREHOLDERS
PA I N T E D P O N Y P E T R O L E U M LT D .
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As at and for the years ended December 31, 2013 and 2012
(c) Stock Options
rate.
(d) Derivatives
Measurement
ongoing basis.
(b) Cash and Cash Equivalents, Trade and Other Receivables, Trade and Other Payables and Bank Debt
The fair value of cash and cash equivalents, trade and other receivables, trade and other payables 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, 2013
and December 31, 2012, 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 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 option holder behavior), expected dividends and the risk-free interest
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 statement of financial position, using the remaining
contracted crude oil and natural gas volumes and risk-free interest rate (based on published government rates).
The Company classifies the fair value of these transactions according to the following hierarchy based on the amount of
observable inputs used to value the instrument.
(i) 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
(ii) 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 Company's commodity price contracts are valued using Level 2 of the hierarchy.
Key management personnel are persons who have the authority and responsibility for planning, directing and controlling the
activities of the Company, directly or indirectly. This includes all directors and executives of the Company. Short-term
compensation includes salaries, bonuses and short-term benefits paid to executives and fees paid to directors. Share-based
payments represents the amortization of share-based payment expense associated with options granted to executives and
16. SUPPLEMENTARY DISCLOSURES
(a) Key Management Personnel Compensation
directors.
Years ended December 31, (000s)
Short-term compensation
Share based payments
Total
2013
2012
$
4,327 $
2,423
$
5,631
9,958
6,308
8,731
$
2013 ANNUAL REPORT TO SHAREHOLDERS
54
PA I N T E D P O N Y P E T R O L E U M LT D .
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As at and for the years ended December 31, 2013 and 2012
(b) Income Statement Presentation
In the Company's 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, 2013, employee
compensation costs of $11.7 million were included in general and administrative expenses (2012: $11.8 million) and $1.0
million were included in operating expenses (2012: $0.2 million).
17. COMMITMENTS
($000s)
Gas processing
Gas gathering
Oil transportation
Equipment leases
Office leases
18. CONTINGENCY
2014
4,087
1,631
466
726
1,331
2015
3,773
700
253
618
2016
3,666
598
90
618
2017
2,820
-
-
144
1,106
2018
2,467
Thereafter
6,314
-
-
-
Total
23,127
2,929
809
2,106
6,912
-
-
-
1,321
1,093
1,119
942
Gas processing includes numerous contracts to process natural gas through third party owned gas processing facilities in
British Columbia. Gas gathering includes contracts to transport natural gas through third party owned pipeline systems in
British Columbia. Oil transportation includes contracts requiring minimum tolls for transportation of crude oil through a major
carrier system in Saskatchewan. Equipment leases include agreements to lease compressors related to the construction of
facility infrastructure, expiring in 2016 and 2017. Office leases include the Company's contractual obligations for office space.
The Company is contingently obligated to pay $0.7 million should a specified Alberta gas index price exceed CDN $5.00 per
gigajoule for an uninterrupted four month period prior to January 11, 2015. The Company is also contingently obligated to pay
an additional $0.2 million should the same index price exceed CDN $6.50 per gigajoule for an uninterrupted four month period
prior to January 11, 2015. The Company estimated the fair value of the contingent consideration to be negligible as at January
11, 2012 and will recognize any change in fair value in earnings until January 11, 2015.
55
2013 ANNUAL REPORT TO SHAREHOLDERS
PA I N T E D P O N Y P E T R O L E U M LT D .
ADVISORY
Certain information regarding Painted Pony set forth in this Annual Report, including its future plans and operations, anticipated well results, and the planning
and development of certain prospects, may constitute forward-looking statements and forward-looking information (collectively “forward-looking
statements”) under applicable securities laws and necessarily involve substantial known and unknown risks and uncertainties. These forward-looking
statements are subject to numerous risks and uncertainties, certain of which are beyond Painted Pony's control, including without limitation, risks associated
with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices,
environmental risks, inability to obtain drilling rigs or other services, capital expenditure costs, including drilling, completion and facility costs, unexpected
decline rates in wells, wells not performing as expected, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient
capital from internal and external sources, the impact of general economic conditions in Canada, the United States and overseas, industry conditions, changes
in laws and regulations (including the adoption of new environmental laws and regulations) and changes in how they are interpreted and enforced, increased
competition, the lack of availability of qualified personnel or management, fluctuations in foreign exchange or interest rates, and stock market volatility and
market valuations of companies with respect to announced transactions and the final valuations thereof. Readers are cautioned that the foregoing list of factors
is not exhaustive. Painted Pony's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-
looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or
if any of them do so, what benefits that the Company will derive therefrom. All subsequent forward-looking statements, whether written or oral, attributable to
the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements.
This Annual Report contains industry benchmarks and terms, such as operating netbacks (calculated on a per unit basis as oil, gas and natural gas liquids
revenues less royalties and transportation and operating costs), which are not recognized measures under International Financial Reporting Standards
(“IFRS”). These measures are commonly utilized in the oil and gas industry and are considered informative for management and stakeholders. Painted Pony's
method of calculating operating netbacks may not be comparable to that used by other companies. Operating netbacks should not be viewed as an alternative
to cash flow from operations or other measures of financial performance calculated in accordance with IFRS.
This Annual Report contains certain forward-looking statements, which are based on numerous assumptions including but not limited to: (i) drilling success;
(ii) production; (iii) future capital expenditures; (iv) cash flows from operating activities (v) future development costs, and finding development and acquisition
cost estimates and (vi) accuracy of reserves and resource estimates. In addition, and without limiting the generality of the foregoing, the key assumptions
underlying the forward-looking statements contained herein include the following: (i) commodity prices will be volatile, and natural gas prices will remain low,
throughout 2014; (ii) capital, undeveloped lands and skilled personnel will continue to be available at the level Painted Pony has enjoyed to date; (iii) Painted
Pony will be able to obtain equipment in a timely manner to carry out exploration, development and exploitation activities; (iv) production rates in 2014 are
expected to show growth from 2013; (v) Painted Pony will have sufficient financial resources with which to conduct the capital program; and (vi) the current
tax and regulatory regime will remain substantially unchanged. The reader is cautioned that certain or all of the forgoing assumptions may prove to be
incorrect.
The forward-looking statements contained in this document are made as at the date of this Annual Report and Painted Pony does not undertake any obligation
to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as
may be required by applicable securities laws.
The reserves data of the Company set forth in this Annual Report are based upon independent evaluations by GLJ Petroleum Consultants Ltd. ("GLJ") and
Sproule Associates Limited ("Sproule") each with an effective date of December 31, 2013 as contained in the consolidated report of GLJ dated February 14,
2014 (the "Painted Pony Reserves Report"). The information contained in this Annual Report in respect of Painted Pony's crude oil, natural gas liquids ("NGLs")
and natural gas reserves and the net present values of future net revenue attributable to such reserves, are as evaluated in the Painted Pony Reserves Report,
based on GLJ's January 1, 2014 forecast prices and costs assumptions. GLJ evaluated the Company's reserves on its British Columbia properties and Sproule
evaluated the Company's reserves on its Saskatchewan properties. Sproule incorporated the GLJ forecast prices and costs assumptions in their evaluation.
GLJ prepared the Painted Pony Reserves Report by consolidating the GLJ evaluation results with the Sproule evaluation results, all run on the GLJ forecast
prices and costs assumptions.
Barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. A 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 primarily applicable at the burner tip and does not represent a value equivalency
at the wellhead. All boe conversions in this Annual Report are derived by converting natural gas to oil in the ratio of six mcf of gas to one barrel of oil. Given that
the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a
conversion ratio of 6:1 may be misleading as an indication of value. Mcfes may be misleading, particularly if used in isolation. A mcfe conversion ratio of 1 bbl: 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.
In addition to evaluating the Company's reserves, GLJ was engaged to prepare an independent contingent resources evaluation of the Company's BC Montney
properties, using forecast prices and costs, dated effective December 31, 2012. The most significant positive and negative factors with respect to the
contingent resources estimates relate to the fact that the field is currently at an evaluation/delineation stage. The Montney formation is aerially extensive in
this region, however well control is limited. Both resources-in-place and productivity may be higher or lower than current estimates. Additional drilling and
testing are required to confirm volumetric estimates and reservoir productivity for the contingent resources to be reclassified as reserves.
2013 ANNUAL REPORT TO SHAREHOLDERS
56
PA I N T E D P O N Y P E T R O L E U M LT D .
ADVISORY
Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using
established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more
contingencies ("contingent resources"). Contingencies which must be overcome to enable the reclassification of contingent resources as reserves can be
categorized as economic, non-technical and technical. The Canadian Oil and Gas Evaluation Handbook identifies nontechnical contingencies as legal,
economic, environmental, political and regulatory matters or a lack of markets. There are several non-technical contingencies that prevent the classification of
the contingent resources estimated above as being classified as reserves. The primary contingency which prevents the classification of the Company's
contingent resources as reserves is the current early stage of development. Additional drilling, completion, and testing data is generally required before Painted
Pony can commit to their development. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated
with a project in the early evaluation stage. Contingent resources are further classified in accordance with the level of certainty associated with the estimates
and may be subclassified based on project maturity and/or characterized by their economic status. As additional drilling takes place, it is expected that the
contingent resources will be booked into the reserves category. Estimates of contingent resources described herein, including the corresponding estimates of
before tax present value estimates, are estimates only; the actual resources may be higher or lower than those calculated in the GLJ British Columbia Montney
Contingent Resources Evaluation. There is no certainty that it will be commercially viable or technically feasible to produce any portion of the resources
described in the evaluation.
The most significant positive and negative factors with respect to the contingent resource estimates relate to the fact that the field is currently at an
evaluation/delineation stage. Resource-in-place, productivity and capital costs may be higher or lower than current estimates. Additional drilling and testing
are required to confirm volumetric estimates and reservoir productivity for the contingent resources to be reclassified as reserves.
Estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties due to the effects of
aggregation.
ultimate hydrocarbon recovery therefrom.
The well test results disclosed in this news release represent short-term results, which may not necessarily be indicative of long-term well performance or
57
2013 ANNUAL REPORT TO SHAREHOLDERS
BOARD OF DIRECTORS
OFFICERS
EXCHANGE LISTING
Chairman
Glenn R. Carley,
President
Selinger Capital Inc.
Calgary, Alberta
Kevin D. Angus
President
KD Angus Corp.
Calgary, Alberta
Allan K. Ashton
Independent Businessman
Priddis, Alberta
Nereus L. Joubert
Independent Businessman
Former Country President
Sasol Canada
Calgary, Alberta
Arthur J. G. Madden
Chief Financial Officer
Crown Point Energy Inc.
Calgary, Alberta
Patrick R. Ward
President & Chief Executive Officer
Painted Pony Petroleum Ltd.
Calgary, Alberta
John H. Van de Pol
Vice President, Finance &
Chief Financial Officer
Bruce G. Hall
Vice President, Land
Edwin S. (Ted) Hanbury
Vice President, Engineering
James D. Reimer
Vice President, Exploration
Mary Kay Axford
Controller
Douglas T. McCartney
Partner, Burstall Winger LLP
Corporate Secretary
GLOSSARY
Patrick R. Ward
The Toronto Stock Exchange
President & Chief Executive Officer
Trading symbol for Common Shares: PPY
L. Barry McNamara
National Bank of Canada
Vice President, Corporate Development
Alberta Treasury Branches
PA I N T E D P O N Y P E T R O L E U M LT D .
CORPORATE INFORMATION
LEGAL COUNSEL
Burstall Winger LLP
AUDITORS
KPMG LLP
BANKERS
Canadian Imperial Bank of Commerce
EVALUATION ENGINEERS
GLJ Petroleum Consultants Ltd.
Sproule Associates Limited
REGISTRAR AND TRANSFER AGENT
Enquiries: cssinquiries@olympiatrust.com
Olympia Trust Company
Calgary, Alberta
1 800 727-4493
HEAD OFFICE
1800, 736 - 6 Ave SW
Calgary, Alberta T2P 3T7
Phone: (403) 475-0440
Fax: (403) 238-1487
Toll Free Investor: 1 (866) 975-0440
Email: info@paintedpony.ca
www.paintedpony.ca
2013 ANNUAL REPORT TO SHAREHOLDERS
58
per day
barrels of oil equivalent (6 mcf of natural gas = 1 barrel of oil equivalent)
barrels
billion cubic feet
gross overriding royalties
thousand barrels of oil equivalent
thousand barrels
thousand cubic feet
million cubic feet
natural gas liquids
/d
boe
bbls
bcf
GOR
mboe
mbbl
mcf
mmcf
NGL
NI 51-101 National Instrument 51-101
WTI
West Texas Intermediate, a benchmark crude oil used for pricing comparison
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PAINTED PONY
PETROLEUM LTD.
1800, 736 - 6 Ave SW
Calgary, Alberta T2P 3T7
Phone: (403) 475-0440
Fax: (403) 238-1487
Toll Free: 1-866-975-0440
www.paintedpony.ca