ANNUAL REPORT
December 31, 2018
2018 HIGHLIGHTS
Petrus Resources Ltd. (“Petrus” or the “Company”) (TSX: PRQ) is pleased to report financial and operating results for the three and twelve
month periods ended December 31, 2018 and to provide 2018 year end reserves information as evaluated by Sproule Associates Limited
("Sproule"). The Company's Management's Discussion and Analysis ("MD&A") and audited consolidated financial statements dated as at
and for the year ended December 31, 2018 are available on SEDAR (the System for Electronic Document Analysis and Retrieval) at
www.sedar.com.
In 2018, the Company's primary objectives were to improve its financial position and to increase its light oil weighting. This was done
in order to increase the value of its production and funds flow per share. The Company's Ferrier Cardium asset base provides optionality
between natural gas and light oil which allows the Company's development program to respond to changes in commodity pricing. The
Company planned to invest $25 to $30 million in 2018, directed toward drilling Cardium light oil wells in Ferrier and targeted debt
reduction of $10 to $15 million. Petrus substantially achieved these objectives in 2018: $24.1 million was invested in 2018 to drill 10
gross (4.3 net) Cardium light oil wells in Ferrier, each with a significantly higher number of multi-stage fracs than had been used in the
past. The Company's December 2018 light oil weighting increased 59% from January 2018 and the full impact of the higher liquids
weighting is expected to be represented in 2019(2). The Company ended 2018 with net debt(1) of $139.2 million, which is an $8.9 million
or 6% decrease since December 31, 2017(1).
•
•
•
•
•
Light oil development - In 2018 Petrus set out to prove its Cardium light oil inventory and maximize its return on investment by
significantly increasing the number of fracture stimulations used in its completion operations. Petrus drilled or participated in
2 gross (0.7 net) Cardium condensate wells during the first half of 2018. Petrus strategically deferred further capital development
until the second half of 2018 in order to permit debt repayment early in the year as well as to provide time to analyze well
performance to evaluate the new completion techniques. The Company’s 2018 operated drilling program resumed in the second
half of 2018 with 5 gross (2.9 net) Cardium light oil wells drilled and fracture stimulated with an average of 76 stages per one
mile lateral length. The December test production, over a 14 day period, attributed to Petrus’ 2.9 net additional wells was
approximately 2,000 boe/d(3), which was comprised of 50% light oil (60% total liquids). The light oil test rates of approximately
1,000 boe/d nearly doubled Petrus’ light oil production reported for the third quarter of 2018 of 1,243 boe/d. Petrus is pleased
with the results of the 2018 drilling program and looks forward to continued development of its Cardium light oil in Ferrier in a
consistent, disciplined manner. The Company plans to drill throughout 2019 within funds flow and repay $1 to $2 million of debt
each quarter. Petrus’ Board of Directors has approved a second quarter 2019 capital budget of $7 to $8 million, based on a
current forecast for commodity futures pricing, anticipated service costs and current activity levels.
Increased liquids weighting - Fourth quarter average production was 7,934 boe/d in 2018 compared to 10,711 boe/d in 2017.
The new liquids production related to the fourth quarter 2018 wells is not reflected for a full quarter as the wells were brought
on stream in December. The new production is more valuable in the current commodity environment as the light oil and total
liquids weighting have increased significantly. The Company's December 2018 light oil weighting increased 59% from January
2018. Similarly, the Company's December 2018 total liquids weighting was 40% which is a 43% increase from January 2018. The
Company's operating netback increased 5% from $14.33 per boe(3) in 2017 to $15.08 per boe in 2018; however the full impact
of the increase in liquids weighting is not reflected due to when the new wells were brought on-stream, in late December.
Company best F&D costs - In 2018, the Company realized Finding and Development (“F&D”) costs of $5.15/boe and $8.16/boe
for Proved Plus Probable (“P+P”) and Total Proved (“TP”), respectively. These finding costs were the best in the Company’s
history. In terms of deploying capital to create reserves volume and value, this was the most effective year Petrus has ever had.
Reserve value growth - Petrus ended 2018 with $316 million and $507 million of Total Proved (“TP”) and Proved Plus Probable
(“P+P”), respectively, reserve values before-tax, discounted at 10%. The reserve values increased by 1% and 5%, respectively,
from the December 31, 2017 Sproule Report. Absent of any changes to the December 31, 2017 Sproule Price forecast, the reserve
values would have increased by 22% and 24%, respectively. In 2018, Petrus was also able to increase its Reserve Life Index in
every reserve category.
Best in class operating costs - Total operating expenses were 6% lower from 2017 at $4.75 per boe in 2018 which is the lowest
operating cost in the Company's history (a 57% decrease since 2012) and marks the third consecutive year of operating cost
reductions. The Company continues to focus on optimizing its cost structure, particularly in the Ferrier area, through facility
ownership and control.
•
•
Funds flow - Petrus generated funds flow of $5.0 million in the fourth quarter of 2018 which is lower than the $13.1 million
generated in the fourth quarter of 2017 primarily due to significantly lower market price of Edmonton light oil and natural gas
(AECO) during the fourth quarter of 2018. Relative to global oil prices (West Texas Intermediate), Western Canadian light oil
traded at historically high differentials in the fourth quarter mainly due to insufficient take away capacity. On December 2, 2018
the Alberta government announced a production curtailment mandate of 325,000 boe/d of Alberta crude oil production effective
January 1, 2019. In February, the Alberta government announced plans to transport 120,000 boe/d via rail by 2020. These
measures were intended to help alleviate current take away capacity constraints impacting Alberta producers and to reduce
storage levels. The temporary production reduction applies to all operators in Alberta producing in excess of 10,000 barrels per
day of oil production. Petrus’ oil production is within the 10,000 barrels per day and therefore the Company is exempt from
reducing production. As aresult of these measures, the differential for Western Canadian light oil prices has tightened significantly.
Commodity price risk mitigation - Petrus utilizes financial derivative contracts to mitigate commodity price risk and provide
stability and sustainability to the Company's economic returns, funds flow and capital development plan. During the fourth
quarter, the Company recognized a $1.3 million ($1.38 per boe) realized gain related to natural gas, offset by a $1.9 million ($2.61
per boe) realized loss related to light oil. As a percentage of fourth quarter 2018 production, Petrus has derivative contracts in
place for 52%, at an average price of $2.00/mcf and 53% at an average price of $68.79/bbl, of its natural gas and oil and natural
gas liquids production, respectively, for 2019.
(1) Refer to "Non-GAAP Financial Measures" in the Management's Discussion & Analysis attached hereto.
(2) Refer to "Advisories - Forward-Looking Statements" in the Management's Discussion & Analysis attached hereto.
(3) Refer to "Advisories - BOE Presentation" in the Management's Discussion & Analysis attached hereto.
PRESIDENT’S MESSAGE
In 2018 Petrus set out to accomplish two main goals: improve our balance sheet, and execute a focused capital program concentrated on
Cardium light oil to raise the Company’s liquids weighting.
By year end we spent $24 million on capital development and reduced our net debt by $9 million or 6%. Since 2015, we have made significant
progress in improving our balance sheet by reducing our net debt by $88 million or 39%. Balance sheet strength remains one of our top
priorities. This attention to leverage improvement continues with our plans for 2019 where we look to further repay our net debt by $1 to $2
million each quarter.
Petrus was also able to make significant headway on increasing our liquids production. Through the high quality inventory of Cardium light oil
locations we have in Ferrier, in 2018 we were able to increase our oil weighting by 59% and bring our total liquids weighting to 40%. We
continue to advance our drilling and completion techniques and in 2019 we are targeting to raise our liquids weighting again through further
Cardium oil development in Ferrier.
Challenged commodity prices and heightened volatility continued to be major themes in 2018 for the Canadian energy market. Partially
offsetting this volatility, Petrus’ production has a number of attributes that successfully aid us in mitigating these challenges. Our reported oil
production is primarily a lighter grade condensate which received a $9/bbl premium to Western Canadian light oil pricing for the year. Similarly,
our natural gas production has a higher than average energy content resulting in a $0.40/mcf premium to AECO pricing. The Company also
has an active hedging program with approximately 65% of our oil and natural gas production hedged during the fourth quarter of 2018. Those
hedges helped insulate us from falling prices and will continue to provide price protection through the contracts we have in place for
approximately half of our 2019 volumes.
We achieved a variety of other operational successes as highlighted by our 2018 reserve and annual report. Our Cardium oil drilling program
was the most efficient in the Company’s history in terms of rate of return and payout. Our F&D costs were also the lowest in the Company’s
history at $5.15/boe and $8.16/boe for Total Proved plus Probable and Total Proved, respectively. The value of both our Total Proved and Total
Proved plus Probable reserves increased year over year despite a decrease in our reserve evaluator's price forecast. Had the price forecast
remained constant, the Company would have seen a 24% increase in our Total Proved plus Probable value. And similar to previous years, while
many operational aspects of Petrus were growing, our operating expenses continued to decline for the third consecutive year and were $4.75/
boe for 2018, the Company’s lowest ever.
By many metrics Petrus had an exceptional year in 2018, and we’re excited about our future. Cardium light oil drilling in Ferrier has been
proven over recent years and we look to further develop this repeatable asset in 2019. Based on the current commodity price environment,
our Cardium light oil locations are offering payouts of less than 10 months, which will again, help the Company further strengthen our balance
sheet and improve our liquids weighting. It continues to be a challenging time for the Canadian energy market, however with a disciplined
approach we continue to make our business stronger and more resilient.
Neil Korchinski
President, Chief Executive Officer and Director
Page |3
RESERVES
Petrus’ 2018 year end reserves were evaluated by independent reserves evaluator Sproule Associates Limited ("Sproule") in accordance with the
definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and National instrument 51-101
- Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) as of December 31, 2018 ("2018 Sproule Report"). Additional reserve information as
required under NI 51-101 will be included in our Annual Information Form for the year ended December 31, 2018, which will be filed on SEDAR.
Petrus has a reserves committee, comprised of independent board members, that reviews the qualifications and appointment of the independent
reserve evaluators. The committee also reviews the procedures for providing information to the evaluators. All booked reserves are based upon annual
evaluations by the independent qualified reserve evaluators conducted in accordance with the COGE Handbook and NI 51-101. The evaluations are
conducted using all available geological and engineering data. The reserves committee has reviewed the reserves information and approved the 2018
Sproule Report.
The following table provides a summary of the Company’s before tax reserves as evaluated by Sproule:
As at December 31, 2018
Total Company Interest (1)(3)
Reserve Category
Proved Producing
Proved Non-Producing
Proved Undeveloped
Total Proved
Proved + Probable Producing
Total Probable
Conventional
Natural Gas
(mmcf)
Light and
Medium
Crude Oil
(mbbl)
52,491
16,980
57,180
126,650
67,773
65,072
1,250
94
1,474
2,818
1,672
2,519
NGL
(mbbl)
Total
(mboe)
NPV 0%(2)
($000s)
NPV 5%(2)
($000s)
NPV 10%(2)
($000s)
3,388
121
4,882
8,391
4,255
4,320
13,386
3,044
15,887
32,317
17,223
17,684
258,437
21,959
249,274
529,671
348,210
390,858
211,579
16,299
172,272
400,149
264,084
262,581
181,588
12,754
121,860
316,203
216,812
190,929
Total Proved Plus Probable
(1)Tables may not add due to rounding.
(2)NPV 0%, NPV 5% and NPV 10% refer to the risked net present value of the future net revenue of the Company's reserves, discounted by Nil, 5% and 10%, respectively
and is presented before tax and based on Sproule's pricing assumptions.
(3)Total company interest reserve volumes are presented above and in the remainder of this annual report are presented as the Company's total working interest before
the deduction of royalties (but after including any royalty interests of Petrus).
507,132
920,528
662,730
191,723
12,710
50,001
5,337
In 2018, Petrus’ development program generated Proved Developed Producing ("PDP") reserve volume additions of 0.6 mmboe which were comprised
of 100% liquids. The Company produced 3.3 mmboe during 2018 and ended the year with 13.4 mmboe of PDP reserve volume. Petrus’ PDP liquids
percentage increased from 28% in 2017 to 35% in 2018.
Petrus ended 2018 with $194.3 million, $316.2 million and $507.1 million of Proved Developed ("PD"), Total Proved ("TP"), and Proved plus Probable
(“P+P”), respectively, reserve value before-tax, discounted at 10%, based on the 2018 Sproule Report. In 2018, the Company realized Finding and
Development (“F&D”) costs(3) of $11.55/boe, $8.16/boe and $5.15/boe for PD, TP and P+P reserves, respectively. PDP F&D costs were materially
influenced by the shut in of uneconomic dry gas volumes in the Foothills; therefore, PD is a more indicative metric for developed finding costs in 2018.
Based on the 2018 Sproule Report, the Company’s PDP reserve value before-tax, discounted at 10% is $ 3.67 per share. On the same basis, the P+P
reserve value is $10.25 per share.
FUTURE DEVELOPMENT COST
Future Development Cost ("FDC") reflects Sproule's best estimate of what it will cost to bring the P+P undeveloped reserves on production. FDC
associated with Petrus' total P+P reserves at December 31, 2018, based on the 2018 Sproule Report, is $290.9 million (undiscounted) and includes 230
gross (128.2 net) booked P+P locations.
Page |4
The following table provides a summary of the Company's FDC as set forth in the 2018 Sproule Report:
Future Development Cost ($000s)
Total Proved
Total Proved + Probable
2018
2019
2020
2021
Thereafter
Total FDC, Undiscounted
Total FDC, Discounted at 10%
67,578
79,748
45,822
1,609
—
194,757
172,129
81,596
147,315
60,356
1,609
—
290,876
255,422
PERFORMANCE RATIOS
The following table highlights annual performance ratios for the Company from 2014 to 2018:
December 31, 2018
December 31, 2017
December 31, 2016
December 31, 2015
December 31, 2014
Proved Producing
FD&A ($/boe) (1)(2)
F&D ($/boe) (1)(2)
Reserve Life Index (yr) (1)
Reserve Replacement Ratio (1)
FD&A Recycle Ratio (1)
Proved Developed
FD&A ($/boe) (1)(2)
F&D ($/boe) (1)(2)
Reserve Life Index (yr) (1)
Reserve Replacement Ratio (1)
FD&A Recycle Ratio (1)
Total Proved
FD&A ($/boe) (1)(2)
F&D ($/boe) (1)(2)
Reserve Life Index (yr) (1)
Reserve Replacement Ratio (1)
FD&A Recycle Ratio (1)
37.76
42.27
4.6
0.2
0.4
11.34
11.55
5.6
0.6
1.4
8.73
8.16
11.1
1.3
1.8
13.05
11.57
4.1
1.6
1.1
16.74
14.62
4.5
1.2
0.9
14.33
12.03
8.0
1.1
1.0
(0.43)
9.89
4.4
0.4
(24.8)
(0.23)
7.69
5.3
0.7
(46.3)
(15.78)
2.46
9.8
0.5
(0.7)
23.18
29.80
5.2
0.7
0.7
39.85
65.74
5.8
0.4
0.4
16.77
21.02
10.9
2.9
0.9
35.35
59.67
4.6
5.9
0.8
32.06
68.87
5.4
6.5
0.9
27.82
122.89
7.3
9.1
1.0
Future Development Cost ($000s)
194,757
182,086
201,556
223,409
122,326
Total Proved + Probable
FD&A ($/boe) (1)(2)
F&D ($/boe) (1)(2)
Reserve Life Index (yr) (1)
Reserve Replacement Ratio (1)
FD&A Recycle Ratio (1)
6.49
5.15
17.1
1.5
2.4
14.87
17.28
12.3
1.7
1.0
Future Development Cost ($000s)
290,876
283,030
350.09
(8.06)
14.6
(0.1)
—
269,144
15.40
19.01
16.4
3.7
1.0
21.49
(604.56)
11.2
12.7
1.3
325,325
199,410
(1)Refer to "Oil and Gas Disclosures" in the Management's Discussion & Analysis attached hereto.
(2)Certain changes in FD&A and F&D produce non-meaningful figures as discussed in "Oil and Gas Disclosures" in the Management's Discussion & Analysis attached hereto.
While FD&A and F&D costs, reserve life index, reserve replacement ratio and finding and development costs are commonly used in the oil and nature gas industry and
have been prepared by management, these terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies
and, therefore, should not be used to make such comparisons.
FD&A and F&D costs take into account reserves revisions during the year on a per boe basis. The aggregate of the exploration and development costs incurred in the
financial year and changes during that year in estimated future development costs generally will not reflect total FD&A and F&D costs related to reserves additions for
that year.
Page |5
NET ASSET VALUE
The following table shows the Company's Net Asset Value ("NAV"), calculated using the price forecast from Sproule:
As at December 31, 2018 ($000s except per share)
Proved Developed
Producing
Total Proved
Proved + Probable
Present Value Reserves, before tax (discounted at 10%) (1)
Undeveloped Land Value (2)
Net Debt (3)
Net Asset Value
Fully Diluted Shares Outstanding (4)
181,588
42,410
(139,214)
84,784
49,492
316,203
42,410
(139,214)
219,399
49,492
507,132
42,410
(139,214)
410,328
49,492
Estimated Net Asset Value per Share
(1)Based on the 2018 Sproule Report, using the forecast future prices and costs.
(2)Based on the exploration and evaluation assets as per the Company's December 31, 2018 audited consolidated financial statements.
(3)See "Non-GAAP Financial Measures" in the Management's Discussion & Analysis attached hereto.
(4)There were no "in-the-money" options or warrants based on the Company's December 31, 2018 closing share price of $0.52, therefore the calculation uses the common
shares outstanding at December 31, 2018.
$1.71
$4.43
$8.29
Page |6
MANAGEMENT’S DISCUSSION & ANALYSIS
The following is Management’s Discussion and Analysis ("MD&A") of the financial and operating results of Petrus Resources Ltd. ("Petrus" or
the "Company") as at and for the year ended December 31, 2018. The MD&A is dated March 13, 2019 and should be read in conjunction with
the Company's audited consolidated financial statements for the years ended December 31, 2018 and 2017. The Company’s consolidated
financial statements are prepared in accordance with Canadian generally accepted accounting principles ("GAAP") which require publicly
accountable enterprises to prepare their financial statements using International Financial Reporting Standards ("IFRS"). Readers are directed
to the "Advisories" section at the end of this MD&A regarding forward-looking statements and boe presentation and to the section "Non-GAAP
Financial Measures" herein.
The principal undertaking of Petrus is the investment in energy assets. The operations of the Company consist of the acquisition, development,
exploration and exploitation of these assets. The Company’s head office is located at 2400, 240 - 4th Avenue SW, Calgary, Alberta, Canada.
Additional information on Petrus, including the most recently filed Annual Information Form ("AIF"), are available under the Company's profile
on SEDAR (the System for Electronic Document Analysis and Retrieval) at www.sedar.com.
Page |2
SELECTED FINANCIAL INFORMATION
OPERATIONS
Average Production
Natural gas (mcf/d)
Oil (bbl/d)
NGLs (bbl/d)
Total (boe/d)
Total (boe)
Natural gas sales weighting
Realized Prices
Natural gas ($/mcf)
Oil ($/bbl)
NGLs ($/bbl)
Total realized price ($/boe)
Royalty income
Royalty expense
Net oil and natural gas revenue ($/boe)
Operating expense
Transportation expense
Operating netback (1) ($/boe)
Realized gain (loss) on derivatives ($/boe)
Other income
General & administrative expense
Cash finance expense
Decommissioning expenditures
Funds flow and corporate netback (1) ($/boe)
FINANCIAL (000s except per share)
Oil and natural gas revenue
Net income (loss)
Net income (loss) per share
Basic
Fully diluted
Funds flow
Funds flow per share
Basic
Fully diluted
Capital expenditures
Net acquisitions (dispositions)
Weighted average shares outstanding
Basic
Fully diluted
As at period end
Common shares outstanding
Basic
Fully diluted
Total assets
Non-current liabilities
Net debt (1)
Twelve months
ended
Dec. 31, 2018
Twelve months
ended
Dec. 31, 2017
Three months
ended
Dec. 31, 2018
Three months
ended
Sept. 30, 2018
Three months
ended
Jun. 30, 2018
Three months
ended
Mar. 31, 2018
37,101
1,402
1,433
9,019
3,292,828
43,747
1,823
1,103
10,217
3,729,095
30,480
1,358
1,496
7,934
730,819
33,461
1,243
1,519
8,338
767,095
39,126
1,484
1,241
9,246
841,316
45,543
1,530
1,475
10,596
953,598
69%
71%
64%
67%
71%
72%
1.73
69.74
40.50
24.40
0.12
(3.54)
20.98
(4.75)
(1.15)
15.08
(0.90)
0.13
(1.57)
(2.51)
(0.14)
10.09
2.39
59.56
31.52
24.26
0.02
(3.56)
20.72
(5.08)
(1.31)
14.33
1.00
—
(0.87)
(1.88)
(0.52)
12.06
1.95
52.26
29.01
21.91
0.10
(3.34)
18.67
(5.28)
(1.17)
12.22
(0.79)
0.37
(1.46)
(3.25)
(0.21)
6.88
1.50
77.24
45.27
25.79
0.32
(3.12)
22.99
(4.95)
(0.98)
17.06
(2.69)
0.08
(1.72)
(2.53)
(0.20)
10.00
1.24
75.29
41.53
22.92
0.05
(2.54)
20.43
(4.57)
(1.17)
14.69
(0.74)
0.12
(1.63)
(2.49)
—
9.95
2.18
73.91
46.50
26.50
0.03
(4.90)
21.63
(4.36)
(1.26)
16.01
0.31
—
(1.50)
(1.96)
(0.23)
12.63
Twelve months
ended
Dec. 31, 2018
80,716
Twelve months
ended
Dec. 31, 2017
90,569
Three months
ended
Dec. 31, 2018
16,064
Three months
ended
Sept. 30, 2018
20,030
Three months
ended
Jun. 30, 2018
19,321
Three months
ended
Mar. 31, 2018
25,301
(3,284)
(111,261)
21,063
(8,048)
(10,615)
(5,684)
(0.07)
(0.07)
33,184
0.67
0.67
24,098
(448)
49,492
49,492
49,492
49,492
341,820
171,646
139,214
(2.28)
(2.28)
45,003
0.92
0.92
72,750
4,741
48,825
48,825
49,492
49,492
353,445
173,272
148,066
0.43
0.43
5,030
0.10
0.10
12,660
(6)
49,492
49,492
49,492
49,492
341,820
171,646
139,214
(0.16)
(0.16)
7,685
0.16
0.16
3,637
(50)
(0.21)
(0.21)
8,364
0.17
0.17
1,745
(269)
49,492
49,492
49,492
49,492
49,492
49,492
322,335
170,908
131,603
49,492
49,492
330,359
172,757
135,111
(0.11)
(0.11)
12,105
0.24
0.24
6,056
(123)
49,492
49,492
49,492
49,492
343,161
174,634
142,238
(1)Refer to "Non-GAAP Financial Measures" in the Management's Discussion & Analysis attached hereto.
(2)Corporate netback is equal to funds flow which is a directly comparable GAAP measure. Petrus analyzes these measures on an absolute value and per unit basis.
Page |3
OPERATIONS UPDATE
Production
Fourth quarter average production by area was as follows:
For the three months ended December 31, 2018
Ferrier
Foothills
Central Alberta
Total
Natural gas (mcf/d)
Oil (bbl/d)
NGLs (bbl/d)
Total (boe/d)
Natural gas sales weighting
22,254
812
1,317
5,837
58%
1,998
160
5
499
66%
6,228
386
174
1,598
65%
30,480
1,358
1,496
7,934
64%
Petrus set out in 2018 to prove its Cardium light oil inventory and maximize its return on investment by significantly increasing the number of
fracture stimulations used in its completion operations. Petrus drilled or participated in 2 gross (0.7 net) Cardium condensate wells during the
first half of 2018. Petrus strategically deferred further capital development until the second half of 2018 in order to permit debt repayment
early in the year as well as to provide time to analyze well performance to evaluate the new completion techniques. The Company’s 2018
operated drilling program resumed in the second half of 2018 with 5 gross (2.9 net) Cardium light oil wells drilled and fracture stimulated with
an average of 76 stages per one mile lateral length. The December test production, over a 14 day period, attributed to Petrus’ 2.9 net additional
wells was approximately 2,000 boe/d, which was comprised of 50% light oil (60% total liquids). The light oil test rates of approximately 1,000
boe/d nearly doubled Petrus’ light oil production reported for the third quarter of 2018 of 1,243 boe/d. Petrus is pleased with the results of
the 2018 drilling program and looks forward to continue development of its Cardium light oil in Ferrier in a consistent, disciplined manner. The
Company plans to drill evenly throughout 2019 within funds flow and repay $1 to $2 million of debt each quarter.
Fourth quarter average production was 7,934 boe/d in 2018 compared to 10,711 boe/d in 2017. Looking at the Company’s recent change in
total boe production rates is inaccurate as an evaluation of potential cash flow and value. In the current commodity price environment, as
liquids weighting increases, cash flow and value can increase despite lower overall boe production. The new liquids production related to the
fourth quarter 2018 wells is not reflected for a full quarter as the wells were brought on-stream in December. The resulting production is more
valuable in the current commodity environment as the light oil and total liquids weighting has increased significantly. The Company's December
2018 light oil weighting increased 59% from January 2018. Similarly, the Company's December 2018 total liquids weighting was 40% which is
a 43% increase from January 2018. The Company's operating netback increased 5% from $14.33 per boe in 2017 to $15.08 per boe in 2018;
however the full impact of the increase in liquids weighting is not reflected due to when the new wells were brought on stream, in late December.
In 2018, the Company's drilling program proved that the Ferrier Cardium asset base provides optionality between natural gas or light oil
development. This optionality permits the Company's development program to be agile and efficiently respond to changes in commodity
pricing.
Petrus’ Board of Directors has approved a first quarter 2019 capital budget of $8 to $10 million, based on a current forecast for commodity
futures pricing, anticipated service costs and current activity levels. Management anticipates that the 2019 capital plan will be fully funded
by funds flow, systematically scheduled evenly through the year to maintain flexibility, and permit debt reduction each quarter. In the first
quarter of 2019 the Company expects to generate funds flow between $10 and $11 million, with the remaining $1 to $2 million to be directed
toward debt repayment. The commodity price assumptions used for the first quarter 2019 capital budget were an average price of $1.31 C$/
GJ for natural gas (AECO) and $53.03 US$/bbl for oil (WTI). Petrus' estimated first quarter average differential for Western Canadian light oil
is estimated at $7.55 US$/bbl. The first quarter capital budget is expected to include the drilling of 5 gross (2.0 net) Cardium wells targeting
the most condensate rich areas within the reservoir.
As part of the 2019 first quarter capital budget, Petrus has drilled 2 gross (1.2 net) Cardium light oil wells. The wells have finished drilling and
offset the recently drilled 5 gross (2.9 net) wells from the fourth quarter 2018 drilling program. The 2 first quarter 2019 wells have 1.5 mile
and 1.0 mile horizontal lateral lengths, respectively. Both wells are being fracture stimulated with 124 and 77 stages, respectively. Completion
operations are currently ongoing and the wells' test volumes can flow inline as the wells were drilled from pre-existing surface locations. Both
wells are expected to be on production by the end of March.
Page |4
Petrus’ Board of Directors has approved a second quarter 2019 capital budget of $7 to $8 million, based on a current forecast for commodity
futures pricing, anticipated service costs and current activity levels. The second quarter budget will allow for debt repayment of $1 to $2
million in the quarter.
Petrus estimates the 2019 capital plan will maintain production year over year, increase its oil and total liquids weighting, and reduce debt
throughout the year. Approximately 85% of the capital plan will be directed to development of Cardium light oil wells in the Ferrier area of
Alberta, which we estimate will have payouts of less than one year and achieve its objective to increase its light oil production weighting and
funds flow.
(1) Refer to "Advisories - Forward-Looking Statements"in the Management's Discussion & Analysis attached hereto.
Page |5
RESULTS OF OPERATIONS
FINANCIAL AND OPERATIONAL RESULTS OF OIL AND NATURAL GAS ACTIVITIES
Average production
Natural gas (mcf/d)
Oil (bbl/d)
NGLs (bbl/d)
Total (boe/d)
Total (boe)
Revenue ($000s)
Natural Gas
Oil
NGLs
Royalty revenue
Oil and natural gas revenue
Average realized prices
Natural gas ($/mcf)
Oil ($/bbl)
NGLs ($/bbl)
Total realized price ($/boe)
Hedging gain (loss) ($/boe)
Total price including hedging
($/boe)
Twelve months
ended
Dec. 31, 2018
Twelve months
ended
Dec. 31, 2017
Three months
ended
Dec. 31, 2018
Three months
ended
Sept. 30, 2018
Three months
ended
Jun. 30, 2018
Three months
ended
Mar. 31, 2018
37,101
1,402
1,433
9,019
43,747
1,823
1,103
10,217
3,292,828
3,729,095
23,453
35,684
21,186
393
80,716
1.73
69.74
40.50
24.40
(0.90)
23.50
38,156
39,633
12,685
95
90,569
2.39
59.56
31.52
24.26
1.00
25.26
30,480
1,358
1,496
7,934
730,819
5,473
6,522
3,993
76
16,064
1.95
52.26
29.01
21.91
(0.79)
21.12
33,461
1,243
1,519
8,338
767,095
4,630
8,828
6,326
246
20,030
1.50
77.24
45.27
25.79
(2.69)
23.10
39,126
1,484
1,241
9,246
841,316
4,432
10,159
4,692
38
19,321
1.24
75.29
41.53
22.92
(0.74)
22.18
45,543
1,530
1,475
10,596
953,598
8,918
10,175
6,175
33
25,301
2.18
73.91
46.50
26.50
0.31
26.81
Average benchmark prices
Twelve months
ended
Dec. 31, 2018
Twelve months
ended
Dec. 31, 2017
Three months
ended
Dec. 31, 2018
Three months
ended
Sept. 30, 2018
Three months
ended
Jun. 30, 2018
Three months
ended
Mar. 31, 2018
Natural gas
AECO 5A ($/GJ)
AECO 7A ($/GJ)
Crude Oil
Mixed Sweet Blend Edm ($/bbl)
Foreign Exchange
US$/C$
1.42
1.45
69.13
0.77
2.04
2.30
62.28
0.77
1.47
1.80
48.12
0.76
1.13
1.28
79.65
0.77
1.12
0.97
78.91
0.78
1.97
1.76
72.28
0.80
Page |6
FUNDS FLOW AND NET INCOME (LOSS)
Petrus generated funds flow of $5.0 million in the fourth quarter of 2018, a decrease relative to the $13.1 million generated in the fourth
quarter of 2017. The decrease is due to 26% lower production, a 28% decrease in light oil pricing (Edm CAD$) and 8% lower natural gas pricing
(AECO 5A). On a twelve month basis, funds flow was 26% lower at $33.2 million in 2018 compared to $45.0 million in the prior year. The
decrease is due to 30% lower natural gas pricing (AECO 5A) and 12% lower production, partially offset by 11% higher light oil pricing (Edm CAD
$).
Petrus reported net income of $21.1 million in the fourth quarter of 2018, compared to a net loss of $67.1 million in the fourth quarter of
2017. The net income in the fourth quarter of 2018 opposed to the net loss in the prior year is primarily due to the accounting for the unrealized
hedging on financial derivatives, as well as the recognition of an impairment loss in the fourth quarter of 2017. The accounting for the unrealized
hedging on financial derivatives had a material impact on earnings; during the fourth quarter of 2017, the Company recognized an unrealized
loss of $1.3 million whereas during the fourth quarter of 2018 a $24.8 million unrealized gain was recorded. The differences are due to changes
in commodity prices at December 31 of the respective years. On a twelve month basis, the Company generated 97% lower net loss of $3.3
million in 2018 compared to $111.3 million in 2017. The decrease in net loss is mainly due to the impairment loss of $109 million recorded in
2017.
($000s except per share)
Three months ended
December 31, 2018
Three months ended
December 31, 2017
Twelve months ended
December 31, 2018
Twelve months ended
December 31, 2017
Funds flow
Funds flow per share - basic
Funds flow per share - fully diluted
Net income (loss)
Net income (loss) per share - basic
Net income (loss) per share - fully diluted
Common shares outstanding (000s)
Basic
Fully diluted
Weighted average shares outstanding (000s)
Basic
Fully diluted
5,030
0.10
0.10
21,063
0.43
0.43
49,492
49,492
49,492
49,492
13,084
0.26
0.26
(67,093
(1.36)
(1.36)
49,492
49,492
49,456
49,456
33,184
0.67
0.67
(3,284)
(0.07)
(0.07)
49,492
49,492
49,492
49,492
45,003
0.92
0.92
(111,261)
(2.28)
(2.28)
49,492
49,492
48,825
48,825
OIL AND NATURAL GAS REVENUE
Average production for the fourth quarter of 2018 was 7,934 boe/d (64% natural gas), 26% lower than the 10,711 boe/d (73% natural gas)
average production for the fourth quarter of the prior year. The 26% decrease is due to certain dry gas production in the Foothills area which
was shut-in due to uneconomic gas prices. The production decrease is also attributable to natural production declines. Total oil and natural
gas revenue for the fourth quarter of 2018 was $16.1 million compared to $23.2 million in the fourth quarter of 2017. The 31% decrease is
due to lower realized oil and natural gas liquids prices and lower production.
Average production for the year ended December 31, 2018 was 9,019 boe/d (69% natural gas), compared to 10,217 boe/d (71% natural gas)
for the prior year. Total oil and natural gas revenue decreased from $90.6 million for the year ended December 31, 2017 to $80.7 million for
the year ended December 31, 2018 mainly due to 12% lower production and 30% lower natural gas pricing (AECO 5A monthly index).
Natural gas
During the three and twelve months ended December 31, 2018, the average benchmark natural gas price in Canada (AECO 5A monthly index)
decreased by 8% and 30%, respectively, from the prior year comparative periods (average price of $1.55 per mcf in the fourth quarter of 2018
compared to $1.69 per mcf in the fourth quarter of the prior year, and $1.50 per mcf for the year ended December 31, 2018, compared to
$2.15 per mcf for the prior year comparative period).
The Company’s average realized natural gas price during the fourth quarter of 2018 was $1.95 per mcf, compared to $1.90 per mcf in the fourth
quarter of 2017, which represents a 3% increase. Natural gas revenue for the fourth quarter of 2018 was $5.5 million and production of
2,804,167 mcf accounted for approximately 64% of fourth quarter production volume and 34% of oil and natural gas revenue, compared to
revenue of $8.1 million and production of 4,289,475 mcf accounting for approximately 73% of fourth quarter production volume and 35% of
oil and natural gas revenue in the prior year comparative period. Natural gas revenue decreased from the prior year due to lower natural gas
prices during the fourth quarter of 2018.
Natural gas revenue for the year ended December 31, 2018 was $23.5 million and production of 13,541,961 mcf accounted for approximately
69% of production volume and 29% of oil and natural gas revenue, compared to revenue of $38.2 million and production of 15,967,547 mcf
Page |7
for 72% of production volume and 42% of oil and natural gas revenue in the prior year. The decrease is due to lower natural gas prices and
production.
Crude oil and condensate
Edmonton Light Sweet crude oil prices decreased 28% from the fourth quarter of 2017 to the fourth quarter of 2018 (an average price of $48.12
per bbl for the fourth quarter of 2018 compared to an average price of $66.93 per bbl for the prior year comparative period). Prices increased
11% from the year ended December 31, 2017 to the year ended December 31, 2018 ($69.13 per bbl in 2018 compared to an average of $62.28
per bbl in 2017).
The average realized price of Petrus’ crude oil and condensate was $52.26 per bbl for the fourth quarter of 2018 compared to $66.10 per bbl
for the same period in the prior year.
Oil and condensate revenue for the fourth quarter of 2018 was $6.5 million and production of 124,809 bbl accounted for approximately 17%
of total production volume and 41% of oil and natural gas revenue, compared to revenue of $11.3 million and production of 170,563 bbl
accounting for approximately 17% of total production volume and 49% of oil and natural gas revenue in the fourth quarter of the prior year.
Oil and condensaterevenue for the year ended December 31, 2018 was $35.7 million and production of 511,698 bbl accounted for approximately
15% of total production volume and 44% of oil and natural gas revenue, compared to revenue of $39.6 million and production of 665,390 bbl
for 18% of total production volume and 44% of oil and natural gas revenue for the year ended December 31, 2017.
Natural gas liquids (NGLs)
The Company’s NGL production mix consists of ethane, propane, butane, pentane and sulphur. The pricing received for NGL production is
based on the product mix, the fractionation process required and the demand for fractionation facilities. In the fourth quarter of 2018, the
overall realized NGL price averaged $29.01 per bbl, compared to $38.00 per bbl in the prior year. The decrease is attributed to lower commodity
prices as well as a change in the composition of the Company's NGLs.
NGL revenue for the fourth quarter of 2018 was $4.0 million and production of 137,649 bbl accounted for approximately 19% of production
volume and 25% of oil and natural gas revenue, compared to revenue of $3.8 million and production of 99,912 bbl accounted for approximately
10% of production volume and 16% of oil and natural gas revenue for the fourth quarter of the prior year.
NGL revenue for the year ended December 31, 2018 was $21.2 million and production of 523,136 bbl accounted for approximately 16% of
production volume and 26% of oil and natural gas revenue in the period, compared to revenue of $12.7 million and production of 402,446 bbl
for 11% of production volume and 14% of oil and natural gas revenue for the year ended December 31, 2017.
ROYALTY EXPENSES
Royalties are paid to the Government of Alberta and to gross overriding royalty owners. The following table shows the Company’s royalty
expenses for the periods shown:
Royalty Expenses ($000s)
Crown
Percent of production revenue
Gross overriding
Total
Three months ended
December 31, 2018
Three months ended
December 31, 2017
Twelve months ended
December 31, 2018
Twelve months ended
December 31, 2017
1,086
7%
1,350
2,436
1,038
4%
1,962
3,000
4,279
5%
7,359
11,638
5,353
6%
7,917
13,270
Total royalty expense (net of royalty allowances and incentives) decreased from $3.0 million in the fourth quarter of 2017 to $2.4 million in
the fourth quarter of 2018 primarily due to 26% lower production and lower commodity pricing.
On a twelve month basis, total royalty expense (net of royalty allowances and incentives) decreased from $13.3 million in 2017 to $11.6 million
in 2018. The decrease is also due to lower production and commodity pricing compared to the prior year.
Gross overriding royalties decreased from $2.0 million in the fourth quarter of 2017 to $1.4 million in the fourth quarter of 2018, due to lower
natural gas prices. Gross overriding royalties were $7.4 million for the twelve months ended December 31, 2018, compared to $7.9 million in
2017. The reduction in the current year is also attributed to lower commodity pricing.
Page |8
RISK MANAGEMENT
The Company utilizes financial derivative contracts to mitigate commodity price risk and provide stability and sustainability to the Company's
economic returns, funds flow and capital development plan. Petrus’ risk management program is governed by guidelines approved by its Board
of Directors.
The impact of the contracts that were outstanding during the reporting periods are actual cash settlements and are recorded as realized hedging
gains (losses). The unrealized gain (loss) is recorded to demonstrate the change in fair value of the outstanding contracts during the financial
reporting period for financial statement purposes. Petrus does not follow hedge accounting for any of its risk management contracts in place.
Petrus considers all of its risk management contracts to be effective economic hedges of its underlying business transactions.
The table below shows the realized and unrealized gain or loss on risk management contracts for the periods shown:
Net Gain (Loss) on Financial Derivatives ($000s)
Three months ended
December 31, 2018
Three months ended
December 31, 2017
Twelve months ended
December 31, 2018
Twelve months ended
December 31, 2017
Realized hedging gain (loss)
Unrealized hedging gain (loss)
Net gain (loss) on derivatives
(573)
25,370
24,797
1,210
(2,518)
(1,308
(2,961)
7,510
4,549
3,732
9,621
13,353
The Company recognized a realized hedging loss of $0.6 million during the fourth quarter of 2018, compared to a $1.2 million gain realized in
the fourth quarter of the prior year. The realized loss in the current period is due to higher light oil prices (WTI CAD/bbl) offset by lower natural
gas prices (relative to the respective contracts outstanding). The realized loss in the fourth quarter of 2018 decreased the Company’s total
realized price by $0.79 per boe, compared to the realized gain in the fourth quarter of the prior year, which increased the Company's total
realized price by $1.23 per boe.
The Company recognized a realized hedging loss of $3.0 million during the twelve months ended December 31, 2018, compared to a $3.7
million gain realized in the prior year. The realized loss in the current year is due to strengthened annual average crude oil prices (WTI CAD/bbl)
whereas in the prior year the gain was due to lower oil and natural gas prices.
The unrealized hedging gain of $25.4 million for the three months ended December 31, 2018 represents the change in the unrealized net risk
management position during the quarter. The unrealized hedging gain of $7.5 million for the twelve months ended December 31, 2018
represents the change in the unrealized net risk management position during 2018. These changes are the result of both the realization of
hedging gains in the period, changes related to contracts entered into during the period as well as changes to commodity prices.
There was a significant change in the Company's net risk management position between the third and fourth quarter of 2018 as a result of
volatility in the quarter ending oil price which is used to calculate the risk management asset or liability mark-to-market value. The WTI price
decreased by 38%, from $73.25 USD/bbl as at September 30, 2018 to $45.41 USD/bbl as at December 31, 2018. On September 30, 2018, the
unrealized risk management net mark-to-market value was a $15.8 million liability compared to December 31, 2018, when the unrealized risk
management net mark-to-market value was a $9.5 million asset which resulted in the $25.4 million unrealized hedging gain recorded in the
fourth quarter of 2018. As at February 28, 2019, the net asset mark-to-market value has decreased since year end due to the increase in WTI
USD/bbl price to $57.22.
The Company’s risk management contracts provide protection from significant changes in crude oil and natural gas commodity prices for 2018,
2019, 2020 and 2021. The Company endeavors to hedge approximately 50 to 70% of its forecast production for the following year, and
approximately 30 to 50% of its forecast production for the subsequent year. The Company's hedging strategy is intended to provide stability
and sustainability to the Company's economic returns, funds flow and capital development plan. A summary of Petrus’ risk management
contracts is included in note 10 of the Company’s consolidated financial statements as at and for the year ended December 31, 2018. The table
below summarizes Petrus’ average crude oil and natural gas hedged volumes. The 1,525 bbl/d average oil hedged for 2019 represents 53% of
fourth quarter 2018 average liquids (oil and NGL) production. The 16,750 GJ/day average natural gas hedged for 2019 represents 55% of fourth
quarter average natural gas production.
The following table summarizes the average and minimum and maximum cap and floor prices for the 2019 to 2021 oil and natural gas contracts
outstanding as at the date of this MD&A:
Page |9
2019
2020
Q1
Q2
Q3
Q4
Avg.(1)
Q1
Q2
Q3
Q4
Avg.(1)
Q1
Oil hedged (bbl/d)
1,650
1,400
1,400
1,650
1,525
1,150
750
550
350
700
Avg. WTI cap price ($C/bbl)
68.46
67.13
69.26
70.45
68.88
72.18
76.92
78.81
76.70
75.32
Avg. WTI floor price ($C/bbl)
68.17
67.13
69.26
70.45
68.80
72.18
76.92
78.81
76.70
75.32
—
—
—
Natural gas hedged (GJ/d)
21,000 16,333 16,000 13,667 16,750 12,500
5,500
3,500
3,167
6,167
2,000
Avg. AECO 7A cap price ($C/GJ)
2.47
1.71
1.70
1.72
1.95
1.72
1.55
Avg. AECO 7A floor price ($C/GJ)
1.71
1.55
(1) The volumes and prices reported are the weighted average volumes and prices for the period.
1.70
2.47
1.72
1.72
1.95
1.58
1.58
1.53
1.53
1.64
1.64
1.50
1.50
2021
Q3
Q2
Q4
Avg.(1)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
500
1.50
1.50
OPERATING EXPENSE
The following table shows the Company’s operating expense for the reporting periods shown:
Operating Expense ($000s)
Operating expense, net (1)
Three months ended
December 31, 2018
Three months ended
December 31, 2017
Twelve months ended
December 31, 2018
Twelve months ended
December 31, 2017
3,851
4,744
4.81
15,652
4.75
18,950
5.08
Operating expense, net ($/boe)
(1) Operating expense is presented net of processing income and overhead recoveries.
5.28
Operating expense (presented net of processing income and overhead recoveries) totaled $3.9 million for the fourth quarter of 2018, a 19%
decrease from the $4.7 million recorded in the fourth quarter of the prior year. This change is attributable to improved operating efficiencies
as well as the 26% decrease in production over the same time period. On a per boe basis, operating expense for the fourth quarter was 10%
higher at $5.28 per boe in 2018 compared to $4.81 per boe in 2017. The increase is due to fixed costs allocated over lower production relative
to the prior year.
For the twelve months ended December 31, 2018, operating expense (presented net of processing income and overhead recoveries) totaled
$15.7 million, a 17% decrease from the $19.0 million incurred in 2017. The decrease is attributable to Petrus' improved operating cost structure
and decreased activity related to well workover projects. During the year ended 2017, Petrus incurred significantly higher non-routine workover
expense, the majority of which was incurred in the Foothills non-core operating area.
TRANSPORTATION EXPENSE
The following table shows transportation expense paid in the reporting periods:
Transportation Expense ($000s)
Transportation expense
Transportation expense ($/boe)
Three months ended
December 31, 2018
Three months ended
December 31, 2017
Twelve months ended
December 31, 2018
Twelve months ended
December 31, 2017
855
1.17
1,233
1.25
3,789
1.15
4,880
1.31
Petrus pays commodity and demand charges for transporting its gas on various pipeline systems. The Company also incurs trucking costs on
the portion of its oil and natural gas liquids production that is not pipeline connected. Transportation expense totaled $0.9 million or $1.17
per boe in the fourth quarter of 2018 ($1.2 million or $1.25 per boe for the prior year comparative period). The lower transportation expense
is related to the 26% decrease in production from the fourth quarter of 2017 to the fourth quarter of 2018.
On a twelve month basis, transportation expense totaled $3.8 million, or $1.15 per boe, compared to $4.9 million or $1.31 per boe in 2017.
The decrease is related to the 12% decrease in production from the twelve months ended December 31, 2018 compared to the prior year.
GENERAL AND ADMINISTRATIVE EXPENSE
The following table illustrates the Company’s general and administrative ("G&A") expense which is shown net of capitalized costs directly
related to exploration and development activities:
Page |10
General and Administrative Expense ($000s)
Three months ended
December 31, 2018
Three months ended
December 31, 2017
Twelve months ended
December 31, 2018
Twelve months ended
December 31, 2017
Gross general and administrative expense
Capitalized general and administrative and overhead
recoveries
General and administrative expense
General and administrative expense ($/boe)
2,248
(1,183)
1,065
1.46
1,681
(1,415)
266
0.27
8,229
(3,045)
5,184
1.57
8,787
(5,535)
3,252
0.87
The Company’s G&A expense consisted of the following expenditures:
General and Administrative Expense ($000s)
Three months ended
December 31, 2018
Three months ended
December 31, 2017
Twelve months ended
December 31, 2018
Twelve months ended
December 31, 2017
Personnel, consultants and directors
Office costs
Regulatory and public company expenses
Gross general and administrative expense
Capitalized general and administrative expense and
overhead recoveries
General and administrative expense
1,248
680
320
2,248
(1,183)
1,065
320
835
526
1,681
(1,415)
266
4,610
2,588
1,031
8,229
(3,045)
5,184
4,803
2,929
1,055
8,787
(5,535)
3,252
Fourth quarter 2018 G&A expense (net of capitalized G&A expense and overhead recoveries) totaled $1.1 million or $1.46 per boe, compared
to $0.3 million or $0.27 per boe in the fourth quarter of 2017. Gross G&A expense (before capitalized G&A expense and overhead recoveries)
was 34% higher than the prior year ($2.2 million in the fourth quarter of 2018 compared to $1.7 million in the fourth quarter of 2017). The
change in fourth quarter G&A is primarily due to the fourth quarter 2017 reversal of $0.9 million short term incentive compensation which
had been accrued earlier in 2017. The change in net G&A expense is also related to higher capital overhead recoveries recognized in the prior
year as a result of higher capital activity in 2017 compared to 2018. The increase on a per boe basis is due to higher net G&A expense and
lower quarterly average production in 2018 compared to 2017.
G&A expense for the year ended December 31, 2018 totaled $5.2 million or $1.57 per boe compared to $3.3 million or $0.87 per boe for the
prior year comparative period. Gross G&A expense (before capitalized G&A expense and overhead recoveries) decreased 6% from $8.8 million
in 2017 to $8.2 million in 2018. The decrease is due to fewer personnel and lower related office and software costs. The increase in total 2018
G&A net of capitalized G&A and overhead recoveries is primarily due to higher capital overhead recoveries recognized in the prior year as a
result of higher capital activity in 2017 compared to 2018, partially offset by lower costs incurred in 2018.
SHARE-BASED COMPENSATION EXPENSE
The following table illustrates the Company’s share-based compensation expense which is shown net of capitalized costs directly related to
exploration and development activities:
Share-Based Compensation Expense ($000s)
Three months ended
December 31, 2018
Three months ended
December 31, 2017
Twelve months ended
December 31, 2018
Twelve months ended
December 31, 2017
Gross share-based compensation expense
Capitalized share-based compensation
Share-based compensation expense
329
(70)
259
258
(82)
176
858
(282)
576
804
(301)
503
Share-based compensation expense (net of capitalized portion) was $0.3 million for the fourth quarter of 2018, which is consistent with the
$0.2 million recognized in the fourth quarter of the prior year.
On a twelve month basis, share-based compensation expense (net of capitalized portion) for the year ended December 31, 2018 was $0.6
million, which is higher than the prior year comparative period ($0.5 million).
Page |11
FINANCE EXPENSE
The following table illustrates the Company’s finance expense which includes cash and non-cash expenses:
Finance Expense ($000s)
Interest expense
Foreign exchange loss (gain)
Total cash finance expense
Deferred financing costs
Accretion on decommissioning obligations
Total finance expense
Three months ended
December 31, 2018
Three months ended
December 31, 2017
Twelve months ended
December 31, 2018
Twelve months ended
December 31, 2017
2,370
—
2,370
174
224
2,768
1,514
1
1,515
406
265
2,186
8,272
1
8,273
637
887
9,797
6,992
2
6,994
406
989
8,389
The Company incurred total finance expense of $2.8 million in the fourth quarter of 2018, comprised of $0.2 million of non-cash accretion of
its decommissioning obligations, $2.4 million of cash interest expense and $0.2 million of amortization of deferred financing fees, both of which
are related to the RCF and Term Loan (as each is defined herein). In the fourth quarter of 2017, the Company incurred total finance expense
of $2.2 million, comprised of $0.2 million in non-cash accretion of its decommissioning obligation, $0.4 million of amortization of deferred
financing fees and $1.5 million cash interest expense.
The Company incurred total finance expense of $9.8 million for the year ended December 31, 2018, compared to $8.4 million in 2017. The
increases in finance expense are due to increases in interest expense from 2017 to 2018 during both the fourth quarter and the year are due
to increases in the underlying prime interest rate. These increases were partially offset by reductions in the amount borrowed under the
Company's outstanding RCF.
DEPLETION AND DEPRECIATION
The following table compares depletion and depreciation expense recorded in the reporting periods shown:
Depletion and Depreciation Expense ($000s)
Three months ended
December 31, 2018
Three months ended
December 31, 2017
Twelve months ended
December 31, 2018
Twelve months ended
December 31, 2017
Depletion and depreciation expense
Depletion and depreciation expense ($/boe)
8,679
11.89
12,654
12.84
40,423
12.28
52,614
14.11
Depletion and depreciation expense is calculated on a unit-of-production (boe) basis. This fluctuates period to period primarily as a result of
changes in the underlying proved plus probable reserve base and in the amount of costs subject to depletion and depreciation, including future
development cost. Such costs are segregated and depleted on an area by area basis relative to the respective underlying proved plus probable
reserve base.
Petrus recorded depletion and depreciation expense in the fourth quarter of 2018 of $8.7 million or $11.89 per boe, compared to the fourth
quarter of 2017, when $12.7 million or $12.84 per boe was recorded. On a twelve month basis, the Company recorded $40.4 million or $12.28
per boe in 2018, compared to $52.6 million or $14.11 per boe for the prior year. The decrease is due to lower production volume. In addition,
the impairment losses incurred in 2017 contributed to a lower depletion per boe rate.
IMPAIRMENT
The following table illustrates impairment losses recorded in the reporting periods:
Impairment ($000s)
Impairment
Total
Three months ended
December 31, 2018
Three months ended
December 31, 2017
Twelve months ended
December 31, 2018
Twelve months ended
December 31, 2017
—
—
64,000
64,000
—
—
109,000
109,000
Petrus recognized an impairment loss of nil for the three and twelve months ended December 31, 2018, compared to the prior year comparative
periods where an impairment loss of $64.0 million and $109.0 million, respectively, was recorded.
During the year ended 2017, management determined that certain CGUs were no longer considered to be core to the Company. As such, a
process was initiated to potentially divest of the Company's Foothills and Central Alberta CGUs. Based on interest in the Foothills and Central
Alberta assets and information obtained through the divestiture process to date, the Company determined there were indicators of impairment.
The Company recorded an impairment loss of $64.0 million and $109.0 million on its property, plant and equipment and exploration and
evaluation assets related to the Foothills and Central Alberta CGUs during the three and twelve month periods ended December 31, 2017,
Page |12
respectively.
As at December 31, 2018, the book value of the Company's net assets was greater than its market capitalization. The Company determined
there to be indicators of impairment on the Foothills and Central Alberta CGUs and performed an impairment test on these two CGUs. No
impairment charge was recorded as the recoverable amounts were higher than their carrying values. The Company did not identify any
indicators of impairment on its Ferrier CGU.
EXPLORATION AND EVALUATION EXPENSE
The following table illustrates exploration and evaluation expense recorded in the reporting periods:
Exploration and Evaluation Expense ($000s)
Three months ended
December 31, 2018
Three months ended
December 31, 2017
Twelve months ended
December 31, 2018
Twelve months ended
December 31, 2017
Exploration and evaluation expense
Total
134
134
148
148
1,938
1,938
2,783
2,783
LOSS (GAIN) ON SALE OF ASSETS
The following table illustrates the loss (gain) on sale of assets during the reporting periods:
Loss (Gain) on Sale of Assets($000s)
Three months ended
December 31, 2018
Three months ended
December 31, 2017
Twelve months ended
December 31, 2018
Twelve months ended
December 31, 2017
Loss (Gain) on sale of assets
Total
SHARE CAPITAL
19
19
624
624
(8)
(8)
1,542
1,542
The Company's authorized share capital consists of an unlimited number of common shares ("Common Shares") and an unlimited number
of preferred shares ("Preferred Shares"). The Company has not issued any Preferred Shares. The following table details the number of issued
and outstanding securities for the periods shown:
Share Capital (000s)
Three months ended
December 31, 2018
Three months ended
December 31, 2017
Twelve months ended
December 31, 2018
Twelve months ended
December 31, 2017
Weighted average Common Shares outstanding
Basic
Fully diluted
Common Shares outstanding
Basic
Fully diluted
Stock options outstanding
49,492
49,492
49,492
49,492
3,083
49,456
49,456
49,492
49,492
2,915
49,492
49,492
49,492
49,492
3,083
48,825
48,825
49,492
49,492
2,915
At December 31, 2018, the Company had 49,491,840 Common Shares and 3,082,880 stock options outstanding.
The Company issued 1,208,880 stock options during the twelve months ended December 31, 2018 as follows:
(a) 549,900 stock options were issued on May 28, 2018 at an exercise price of $1.49.
(b) 508,500 stock options were issued on August 17, 2018 at an exercise price of $0.86.
(c) 150,480 stock options were issued on November 19, 2018 at an exercise price of $0.77.
The Company has a deferred share unit plan in place whereby it may issue deferred share units to directors of the Company. At December 31,
2018, 382,796 (December 31, 2017 – 130,038) deferred share units were issued and outstanding. Each DSU entitles the participants to receive,
at the Company's discretion, either shares of the Company or cash equivalent to the number of DSUs multiplied by the trading price of the
equivalent number of shares of the Company. All DSUs granted vest and become payable upon retirement of the director.
Page |13
LIQUIDITY AND CAPITAL RESOURCES
At December 31, 2018, Petrus had two debt instruments outstanding. The first is a reserve-based, senior secured revolving credit facility with
a syndicate of lenders, which is comprised of an operating facility and a syndicated term-out facility (together, the “Revolving Credit Facility”
or “RCF”). The second is a subordinated secured term loan (the “Term Loan”).
(a) Revolving Credit Facility
At December 31, 2018, the RCF was comprised of a $20 million operating facility and a $90 million syndicated term-out facility. Consent
from the syndicate lenders and the Term Loan lender is required for total borrowings against the RCF exceeding $105 million. The
syndicated term-out facility has a revolving period that ends May 31, 2019 at which time it will either be renewed or converted to a
one-year term facility. The Company has provided collateral by way of a debenture over all of the present and after acquired property
of the Company.
At December 31, 2018, the Company had drawn $97.0 million against the RCF and had a $0.7 million letter of credit outstanding against
the RCF (December 31, 2017 – $97.6 million outstanding against the RCF and $0.3 million letter of credit).
The amount of the RCF is subject to a borrowing base review performed on a semi-annual basis by the lenders, based primarily on
reserves and commodity prices estimated by the lenders as well as other factors. In addition, asset dispositions require unanimous
lender consent. A decrease in the borrowing base could result in a reduction to the available credit under the RCF. The next scheduled
borrowing base redetermination date for the RCF is on or before May 31, 2019.
(b) Term Loan
At December 31, 2018, the Company had a $35 million (December 31, 2017 – $35 million) Term Loan outstanding (excluding $0.6 million
of deferred finance fees), which is due October 8, 2020. The Term Loan bears interest which is due and payable monthly and accrues
at a per annum rate of the (three-month) Canadian Dealer offered Rate (CDOR) plus 700 basis points. The Company has provided
collateral by way of a debenture over all of the present and after acquired property of the Company.
Financial Covenants
The RCF and the Term Loan carry financial covenants that are described in note 8 of the Company's December 31, 2018 consolidated financial
statements. The Company was in compliance with all financial covenants at December 31, 2018.
Liquidity Risk
Liquidity risk relates to the risk the Company will encounter difficulty in meeting obligations associated with its financial liabilities that are
settled by cash as they become due. The Company’s approach to managing liquidity risk is to ensure, as much as possible, that it will have
sufficient liquidity to meet its short-term and long-term financial obligations when due, under both normal and unusual conditions without
incurring unacceptable losses or risking harm to the Company’s reputation. The financial liabilities on its balance sheet consist of bank
indebtedness, accounts payable, long term debt and risk management liabilities. The Company anticipates it will continue to have adequate
liquidity to fund its financial liabilities through funds flow and available credit capacity from its RCF.
Typically the Company ensures that it has sufficient cash on demand to meet expected operational expenses for a normal period. To achieve
this objective, the Company prepares annual capital expenditure budgets, which are regularly monitored and updated as considered necessary.
Further, the Company utilizes authorizations for expenditures on operated and non-operated projects to further manage capital expenditures.
The Company also attempts to match its payment cycle with collection of oil and natural gas revenue on the 25th day of each month.
As at December 31, 2018, the Company had a working capital deficiency (excluding risk management assets and liabilities and director share
unit liabilities) of $7.8 million. The Company plans to address this working capital deficiency by using its funds flow and available credit facilities.
The next scheduled borrowing base redetermination date for the RCF is on or before May 31, 2019. Petrus anticipates it will continue to have
adequate liquidity to fund its financial liabilities through funds flow and available credit capacity from its RCF.
The following are the contractual maturities of financial liabilities as at December 31, 2018:
$000s
Accounts payable
Bank indebtedness and long term debt(1)
Total
(1)Excludes deferred finance fees.
Total
21,646
132,380
154,026
Page |14
< 1 year
21,646
380
22,026
1-5 years
—
132,000
132,000
The commitments for which the Company is responsible are as follows:
$000s
Corporate office lease
Firm service transportation
Total commitments
Total
775
19,739
20,515
< 1 year
715
1,374
2,089
1-5 years
60
12,870
12,930
> 5 years
—
5,495
5,495
Risk Management
Petrus is engaged in the acquisition, development, exploration and exploitation of oil and natural gas in western Canada. The Company is
exposed to a number of risks, both financial and operational, through the pursuit of its strategic objectives. Actively managing these risks
improves the ability to effectively execute Petrus' business strategy. Financial risks associated with the oil and natural gas industry include
fluctuations in commodity prices, interest rates, currency exchange rates and the cost of goods and services. Financial risks also include third
party credit risk and liquidity risk. Operational risks include reservoir performance uncertainties, competition, regulatory, environment and
safety concerns.
Fora more in-depth discussion of risk management, see notes 10 and 15 of the Company’s December 31, 2018 consolidated financialstatements.
CAPITAL EXPENDITURES
Capital expenditures (excluding acquisitions and dispositions) totaled $12.7 million in the fourth quarter of 2018, compared to $21.9 million
in the fourth quarter of the prior year. For the twelve months ended December 31, 2018, Petrus invested $24.1 million compared to $72.8
million in 2017. The decrease in capital spending is related to decreased capital activity as a result of lower natural gas commodity pricing, as
well as the Company's strategic decision to allocate funds flow to debt reduction. The following table shows capital expenditures for the
reporting periods indicated. All capital is presented before decommissioning obligations.
Capital Expenditures ($000s)
Drill and complete
Oil and gas equipment
Geological
Land and lease
Office
Capitalized general and administrative
Total capital expenditures
Gross (net) wells spud
Three months ended
December 31, 2018
Three months ended
December 31, 2017
Twelve months ended
December 31, 2018
Twelve months ended
December 31, 2017
10,503
1,636
—
23
60
438
12,660
6 (2.7)
17,435
3,619
—
—
105
726
21,885
3 (1.4)
16,510
4,177
—
1,635
58
1,718
24,098
10 (4.3)
51,283
18,618
227
343
197
2,082
72,750
19 (13.2)
The following table summarizes the acquisitions and dispositions for the reporting periods indicated:
Acquisitions and Dispositions ($000s)
Acquisitions
Dispositions
Total acquisitions and dispositions
Three months ended
December 31, 2018
Three months ended
December 31, 2017
Twelve months ended
December 31, 2018
Twelve months ended
December 31, 2017
—
(6)
(6)
789
—
789
—
(448)
(448)
9,578
(4,837)
4,741
Net A&D activity totaled $0.01 million in the three months ended December 31, 2018, compared to the prior year period which totaled $0.79
million. During the year ended December 31, 2018, Petrus divested non-core assets for approximately $0.4 million (compared to net A&D
activity in 2017 of $4.8 million).
Page |15
SUMMARY OF QUARTERLY RESULTS
($000s unless otherwise noted)
Dec. 31,
2018
Sept. 30,
2018
Jun. 30,
2018
Mar. 31,
2018
Dec. 31,
2017
Sept. 30,
2017
Jun. 30,
2017
Mar. 31,
2017
Average Production
Natural gas (mcf/d)
Oil (bbl/d)
NGLs (bbl/d)
Total (boe/d)
Total (boe)
Financial Results
Oil and natural gas revenue
Royalty expense
Net oil and natural gas revenue
Transportation expense
Operating expense
Operating netback
Realized gain (loss) on derivatives
Other income
General & administrative expense
Cash finance expense
Decommissioning expenditures
Corporate netback and funds flow
Oil and natural gas revenue
Per share - basic
Per share - fully diluted
Net income (loss)
Per share - basic
Per share - fully diluted
Common shares outstanding (000s)
Basic
Fully diluted
Weighted avg. shares outstanding (000s)
Basic
Fully diluted
Total assets
Net debt
30,480
33,461
39,126
45,543
46,625
45,550
42,392
40,332
1,358
1,496
7,934
1,243
1,519
8,338
1,484
1,241
9,246
1,530
1,475
1,854
1,086
1,877
1,098
2,015
1,160
10,596
10,711
10,567
10,240
1,542
1,067
9,331
730,819
767,095
841,316
953,598
985,388
972,140
931,821
839,746
16,064
20,030
19,321
25,301
23,243
18,299
26,753
22,274
(2,436)
(2,391)
(2,137)
(4,674)
(3,000)
(2,656)
(4,306)
(3,309)
13,628
17,639
17,184
20,627
20,243
15,643
22,447
18,965
(855)
(749)
(988)
(1,197)
(1,233)
(1,255)
(1,235)
(1,157)
(3,851)
(3,800)
(3,841)
(4,160)
(4,744)
(5,271)
(5,155)
(3,780)
8,922
13,090
12,355
15,270
14,266
9,117
16,057
14,028
(573)
(2,061)
268
69
(625)
103
298
—
1,210
1,829
—
—
212
—
482
—
(1,065)
(1,317)
(1,372)
(1,430)
(266)
(1,059)
(1,047)
(882)
(2,370)
(1,941)
(2,097)
(1,865)
(1,515)
(1,936)
(1,807)
(1,736)
(152)
5,030
(155)
7,685
—
(168)
(611)
(224)
(957)
(160)
8,364
12,105
13,084
7,727
12,458
11,732
16,064
20,030
19,321
25,301
23,243
18,299
26,753
22,274
0.32
0.32
0.40
0.40
0.39
0.39
0.51
0.51
0.47
0.47
0.37
0.37
21,063
(8,048)
(10,615)
(5,684)
(67,095)
(50,696)
0.43
0.43
(0.16)
(0.16)
(0.21)
(0.21)
(0.11)
(0.11)
(1.36)
(1.36)
(1.03)
(1.03)
0.54
0.54
(781)
(0.02)
(0.02)
0.48
0.47
7,311
0.15
0.16
49,492
49,492
49,492
49,492
49,492
49,492
49,492
49,492
49,492
49,492
49,428
49,428
49,428
49,428
49,428
52,664
49,492
49,492
49,492
49,492
49,492
49,492
49,492
49,492
49,456
49,456
49,428
49,428
49,428
49,428
46,754
46,989
341,820
322,335
330,359
343,161
353,445
409,078
465,794
460,095
(139,214)
(131,603)
(135,111)
(142,238)
(148,066)
(137,531)
(137,069)
(130,624)
The oil and natural gas exploration and production industry is cyclical in nature. Petrus' financial position, results of operations and corporate
netback are affected by commodity prices, exchange rates, Canadian price differentials and production levels. Petrus’ average quarterly
production decreased from 9,331 boe/d in the first quarter of 2017 to 7,934 boe/d in the fourth quarter of 2018. The 15% production decrease
is attributable to certain production volume in the Foothills area being shut-in due to uneconomic natural gas pricing, partially offset by
incremental volume attributed to the Company's development program at Ferrier.
Commodity price improvements enable higher reinvestment in exploration, development and acquisition activities in future periods as they
increase the cash flows from operating activities. Commodity price reductions reduce revenues received and can challenge the economics of
the Company's development program as the quantity of reserves may not be economically recoverable. Petrus' investment in its assets, and
its ability to replace and grow reserve volumes, will be dependent on its ability to obtain debt and equity financing as well as the funds it
receives from operations.
Page |16
SELECTED ANNUAL INFORMATION
($000s unless otherwise noted)
For the year ended,
Oil and natural gas revenue
Per share - basic
Per share - fully diluted
Net loss
Per share - basic
Per share - fully diluted
Common shares outstanding (000s)
Basic
Fully diluted
Weighted avg. shares outstanding (000s)
Basic
Fully diluted
Total assets
Non-current liabilities
CRITICAL ACCOUNTING ESTIMATES
December 31, 2018
December 31, 2017
December 31, 2016
80,716
1.63
1.63
(3,284)
(0.07)
(0.07)
49,492
49,492
49,492
49,492
341,820
171,646
90,569
1.85
1.85
(111,261)
(2.28)
(2.28)
49,492
49,492
48,825
48,825
353,445
173,272
64,840
1.46
1.46
(67)
(1.51)
(1.51)
45,349
45,349
44,429
44,429
439,967
118,934
The timely preparation of financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions
that affect the application of accounting policies and reported amounts of assets and liabilities and income and expenses. Accordingly, actual
results may differ from these estimates. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting
estimates are recognized in the period in which the estimates are revised and in any future periods affected. Significant estimates and judgments
made by management in the preparation of the financial statements are outlined below. The Company’s critical accounting estimates can be
read in note 2 to the Company’s consolidated financial statements as at and for the year ended December 31, 2018.
OTHER FINANCIAL INFORMATION
Significant accounting policies
The Company’s significant accounting policies can be read in note 3 of the Company’s audited consolidated financial statements as at and
for the year ended December 31, 2018.
New standards and interpretations
IFRS 9 - Financial Instruments
On January 1, 2018, Petrus adopted IFRS 9 Financial Instruments, which includes a principle-based approach for classification and measurement
of financial assets and a forward-looking ‘expected credit loss’ model. The classification and measurement of financial instruments under IFRS
9 did not have a material impact on Petrus’ consolidated financial statements. In addition, the application of the expected credit loss model
to financial assets classified as amortized cost did not result in a material adjustment on transition. IFRS 9 was applied retrospectively in
accordance with transition requirements with no impact to opening retained earnings or comparative periods.
IFRS 15 - Revenue from Contracts with Customers
Petrus adopted IFRS 15 "Revenue from Contracts with Customers" effective January 1, 2018, which establishes a comprehensive framework
for determining whether, how much, and when revenue from contracts with customers is recognized. Petrus' revenue relates to the sale of
petroleum and natural gas tocustomersatspecified delivery points at benchmark prices. Petrus adopted IFRS 15 using the modified retrospective
approach. Under this transitional provision, the cumulative effect of initially applying IFRS 15 is recognized on the date of initial application as
an adjustment to retained earnings. No adjustment to retained earnings was required upon adoption of IFRS 15. The adoption of IFRS 15 did
not materially impact the timing or measurement of revenue. However, IFRS 15 contains new disclosure requirements.
Page |17
IFRS 16 - Leases
IFRS 16 was issued in January 2016 and it replaces IAS 17 Leases, IFRIC 4 Determining whether an Arrangement contains a Lease, SIC-15
Operating Leases-Incentives and SIC-27 Evaluating the Substance of Transactions Involving the Legal Form of a Lease. IFRS 16 sets out the
principles for the recognition, measurement, presentation and disclosure of leases and requires lessees to account for all leases under a single
on-balance sheet model similar to the accounting for finance leases under IAS 17. The standard includes two recognition exemptions for lessees
– leases of ’low-value’ assets (e.g., personal computers) and short-term leases (i.e., leases with a lease term of 12 months or less). At the
commencement date of a lease, a lessee will recognize a liability to make lease payments (i.e., the lease liability) and an asset representing
the right to use the underlying asset during the lease term (i.e., the right-of-use asset). Lessees will be required to separately recognize the
interest expense on the lease liability and the depreciation expense on the right-of-use asset.
Lessees will be also required to remeasure the lease liability upon the occurrence of certain events (e.g., a change in the lease term, a change
in future lease payments resulting from a change in an index or rate used to determine those payments). The lessee will generally recognize
the amount of the remeasurement of the lease liability as an adjustment to the right-of-use asset.
IFRS 16 is effective for annual periods beginning on or after January 1, 2019. A lessee can choose to apply the standard using either a full
retrospective or a modified retrospective approach. The standard’s transition provisions permit certain reliefs. Petrus is finalizing its review of
identified leases and arrangements qualifying as leases under IFRS 16 and is in the process of determining the financial impact of identified
leases on its consolidated financial statements. Petrus expects to adopt IFRS 16 using the modified retrospective approach.
On initial adoption, the Company expects to use the following practical expedients permitted under the standard:
1.
2.
3.
4.
Apply a single discount rate to a portfolio of leases with similar characteristics;
Account for leases with a remaining term of less than 12 months as at January 1, 2019 as short-term leases;
Account for lease payments as an expense and not recognize a right-of-use (“ROU”) asset if the underlying asset is of low dollar value;
The use of hindsight in determining the lease term where the contract contains terms to extend or terminate the lease; and
The Company has identified ROU assets and lease liabilities primarily related to office space. The Company has completed an initial assessment
but not yet finalized the potential impact on its consolidated financial statements.
Disclosure Controls and Procedures
Petrus’ Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, disclosure controls
and procedures ("DC&P"), as defined by National Instrument 52-109 – Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI
52-109”), to provide reasonable assurance that: (i) material information relating to the Company is made known to the Company's Chief
Executive Officer and Chief Financial Officer by others, particularly during the period in which the annual 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. The Chief
Executive Officer and Chief Financial Officer of Petrus have evaluated, or caused to be evaluated under their supervision, the effectiveness
of the Company's DC&P as at December 31, 2018 and have concluded that the Company's DC&P are effective at December 31, 2018 for the
foregoing purposes.
Internal Control over Financial Reporting
Internal control over financial reporting (“ICFR”), as defined in NI 52-109, includes those policies and procedures that: (i) pertain to the
maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of assets of Petrus; (ii) are
designed to provide reasonable assurance that transactions are recorded as necessary to permit preparation of the consolidated financial
statements in accordance with generally accepted accounting principles and that receipts and expenditures of Petrus are being made in
accordance with authorizations of management and Directors of Petrus; and (iii) are designed to provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on
the consolidated financial statements.
The Chief Executive Officer and the Chief Financial Officer are responsible for establishing and maintaining ICFR for Petrus. For the year ended
December 31, 2018, they have designed ICFR, or caused it to be designed under their supervision, to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. The control
framework used to design the Company’s ICFR is the framework in Internal Control – Integrated Framework (2013) issued by the Committee
of Sponsoring Organizations of the Treadway Commission.
Under the supervision of the Chief Executive Officer and the Chief Financial Officer, Petrus conducted an evaluation of the effectiveness of
the Company’s ICFR as at December 31, 2018. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that
as at December 31, 2018, Petrus maintained effective ICFR. It should be noted that while the Chief Executive Officer and Chief Financial Officer
believe that the Company’s controls provide a reasonable level of assurance with regard to their effectiveness, a control system, no matter
Page |18
how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system will be met
and it should not be expected that the control system will prevent all errors or fraud.
NON-GAAP FINANCIAL MEASURES
This MD&A makes reference to the terms "operating netback", "corporate netback", "net debt" and "net debt to funds flow." These indicators
are not recognized measures under GAAP (IFRS) and do not have a standardized meaning prescribed by GAAP (IFRS). Accordingly, the Company's
use of these terms may not be comparable to similarly defined measures presented by other companies. Management uses these terms for
the reasons set forth below.
Operating Netback
Operating netback is a common non-GAAP financial measure used in the oil and natural gas industry which is a useful supplemental measure
to evaluate the specific operating performance by product at the oil and natural gas lease level. The most directly comparable GAAP measure
to operating netback is funds flow. Operating netback is calculated as oil and natural gas revenue less royalties, operating and transportation
expenses. It is presented on an absolute value and per unit basis.
Funds Flow and Corporate Netback
Corporate netback is a common non-GAAP financial measure used in the oil and natural gas industry which evaluates the Company’s profitability
at the corporate level. Corporate netback is equal to funds flow which is a directly comparable GAAP measure. Petrus analyzes these measures
on an absolute value and per unit basis. Management believes that funds flow and corporate netback provide information to assist a reader
in understanding the Company's profitability relative to current commodity prices. It is calculated as the operating netback less general and
administrative expense, finance expense, decommissioning expenditures, plus other income and the net realized gain (loss) on financial
derivatives.
Oil and natural gas revenue
Royalty expense
Net oil and natural gas revenue
Transportation expense
Operating expense
Operating netback
Realized gain (loss) on financial derivatives
Other income
General & administrative expense
Cash finance expense
Decommissioning expenditures
Funds flow and corporate netback
Three months ended
Dec. 31, 2018
Three months ended
Dec. 31, 2017
Twelve months ended
Dec. 31, 2018
Twelve months ended
Dec. 31, 2017
$000s
$/boe
$000s
$/boe
$000s
$/boe
$000s
$/boe
16,064
(2,436)
13,628
(855)
(3,851)
8,922
(573)
267
(1,065)
(2,370)
(151)
5,030
22.01
(3.34)
18.67
(1.17)
(5.28)
12.22
(0.79)
0.37
(1.46)
(3.25)
(0.21)
6.88
23,243
(3,000)
20,243
(1,233)
(4,744)
14,266
1,210
—
(266)
(1,515)
(611)
23.59
80,716
24.52
90,569
(3.04)
(11,638)
(3.54)
(13,270)
20.55
(1.25)
(4.81)
69,078
(3,789)
(15,652)
20.98
(1.15)
(4.75)
77,299
(4,880)
(18,950)
14.49
49,637
15.08
53,469
1.23
—
(0.27)
(1.54)
(0.62)
(2,961)
440
(5,184)
(8,273)
(475)
(0.90)
0.13
(1.57)
(2.51)
(0.14)
3,732
—
(3,252)
(6,994)
(1,952)
24.28
(3.56)
20.72
(1.31)
(5.08)
14.33
1.00
—
(0.87)
(1.88)
(0.52)
13,084
13.29
33,184
10.09
45,003
12.06
Net Debt
Net debt is a non-GAAP financial measure and is calculated as current assets (excluding unrealized financial derivative assets) less current
liabilities (excluding unrealized financial derivative liabilities and deferred share unit liabilities) and long term debt. Petrus uses net debt as
a key indicator of its leverage and strength of its balance sheet. There is no GAAP measure that is reasonably comparable to net debt.
($000s)
Adjusted current assets (1)
Less: adjusted current liabilities (1)
Less: long term debt
Net debt
(1)Adjusted for unrealized risk management assets, liabilities and unrealized deferred share units liabilities.
As at December 31, 2018
As at December 31, 2017
14,035
(21,827)
(131,422)
(139,214)
13,042
(29,201)
(131,907)
(148,066)
Page |19
Net Debt to Funds Flow
Net debt to funds flow is calculated as the period ending net debt divided by the trailing quarter funds flow (annualized).
OIL AND GAS DISCLOSURES
Our oil and gas reserves statement for the year ended December 31, 2018, which includes disclosure of our oil and natural gas reserves and
other oil and natural gas information in accordance with NI 51-101, is contained in the AIF. The recovery and reserve estimates contained herein
are estimates only and there is no guarantee that the estimated reserves will be recovered.
This MD&A contains metrics commonly used in the oil and natural gas industry, such as "finding and development costs" or "F&D", "finding,
development and acquisition costs" or "FD&A", "future development cost" or "FDC", "reserve life index" and "reserve replacement ratio."
These terms do not have standardized meanings or standardized methods of calculation and therefore may not be comparable to similar
measures presented by other companies, and therefore should not be used to make such comparisons. Such metrics have been included herein
to provide readers with additional information to evaluate the Company’s performance, however such metrics should not be unduly relied
upon.
F&D and FD&A Costs
FD&A cost is defined as capital costs for the time period including change in FDC divided by change in reserves including revisions and production
for that same time period. F&D cost is defined as capital costs for the time period including change in FDC divided by change in reserves
including revisions and production for that same time period, excluding acquisitions and dispositions. Both F&D and FD&A costs take into
account reserve revisions during the year on a per boe basis. The methodology used to calculate F&D costs includes disclosure required to
bring the proved undeveloped and probable reserves to production. Annually, changes in forecast FDC occur as a result of Petrus’ development,
acquisition and disposition activities, undeveloped reserve revision and capital cost estimates. These values reflect the independent evaluator’s
best estimate of the cost to bring the proved and probable undeveloped reserves to production.
Reserve Life Index
Reserve life index is defined as total reserves by category divided by the annualized fourth quarter production.
Reserve Replacement Ratio
The reserve replacement ratio is calculated by dividing the yearly change in reserves net of production by the actual annual production for the
year.
Reserve Recycle Ratio
The reserve replacement ratio is calculated by dividing field netback by FD&A.
Management uses oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare Petrus'
operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented
in this MD&A, should not be relied upon for investment.
ADVISORIES
Basis of Presentation
Financial data presented above has largely been derived from the Company’s financial statements, prepared in accordance with GAAP which require
publicly accountable enterprises to prepare their financial statements using IFRS. Accounting policies adopted by the Company are set out in the notes
to the audited financial statements as at and for the twelve months ended December 31, 2018. The reporting and the measurement currency is the
Canadian dollar. All financial information is expressed in Canadian dollars, unless otherwise stated.
Forward-Looking Statements
Certain information regarding Petrus set forth in this MD&A contains forward-looking statements within the meaning of applicable securities law, that
involve substantial known and unknown risks and uncertainties. The use of any of the words “anticipate”, “continue”, “estimate”, “expect”, “may”,
“will”, “project”, “should”, “believe” and similar expressions are intended to identify forward-looking statements. Such statements represent Petrus’
internal projections, estimates or beliefs concerning, among other things, an outlook on the estimated amounts and timing of capital investment,
anticipated future debt, production, revenues or other expectations, beliefs, plans, objectives, assumptions, intentions or statements about future
events or performance. These statements are only predictions and actual events or results may differ materially. Although Petrus believes that the
expectations reflected in the forward-looking statements are reasonable, it cannot guarantee future results, levels of activity, performance or
achievement since such expectations are inherently subject to significant business, economic, competitive, political and social uncertainties and
contingencies. Many factors could cause Petrus’ actual results to differ materially from those expressed or implied in any forward-looking statements
made by, or on behalf of, Petrus.
Page |20
In particular, forward-looking statements included in this MD&A include, but are not limited to, statements with respect to: Petrus’ business plan and
capital expenditure program for 2019, including its first quarter capital budget and the funding of the same; Petrus' drilling plan, including the same
being within funds flow; expected 2019 quarterly debt repayment; Petrus' liquid weighting; the results and success of Petrus' hedging program; the
growth of Petrus; expectations regarding Petrus' balance sheet; expectations regarding the adequacy of Petrus' liquidity and the funding of its financial
liabilities; expected year over year production; sources of and sufficient financing and the requirement therefor; expected funds flow for the first
quarter of 2019; the performance characteristics of the Company’s crude oil, NGL and natural gas properties including estimated production and
production dates; Petrus' adoption of IFRS 16 and the impact of the same; the development of the Company's Cardium light oil in Ferrier; future
prospects; the focus of and timing of capital expenditures; access to debt and equity markets; projections of market prices and costs; the performance
characteristics of the Company’s crude oil, NGL and natural gas properties including estimated production; crude oil, NGL and natural gas production
levels and product mix; Petrus’ future operating and financial results; capital investment programs; supply and demand for crude oil, NGL and natural
gas; future royalty rates; drilling, development and completion plans and the results therefrom; and treatment under governmental regulatory regimes
and tax laws. In addition, statements relating to “reserves” are deemed to be forward-looking statements, as they involve the implied assessment,
based on certain estimates and assumptions, that the reserves described can be profitably produced in the future.
This MD&A discloses drilling locations, which are proved plus probable locations as at December 31, 2018 based on the Sproule Report. The drilling
locations on which the Company will actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions,
oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors.
These forward-looking statements are subject to numerous risks and uncertainties, most of which are beyond the Company’s control, including the
impact of general economic conditions; volatility in market prices for crude oil, NGL and natural gas; industry conditions; currency fluctuation;
imprecision of reserve estimates; liabilities inherent in crude oil and natural gas operations; environmental risks; incorrect assessments of the value
of acquisitions and exploration and development programs; competition; the lack of availability of qualified personnel or management; changes in
income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry; hazards such as fire, explosion, blowouts, cratering,
and spills, each of which could result in substantial damage to wells, production facilities, other property and the environment or in personal injury;
stock market volatility; ability to access sufficient capital from internal and external sources; completion of the financing on the timing planned and
the receipt of applicable approvals; and the other risks. With respect to forward-looking statements contained in this MD&A, Petrus has made
assumptions regarding: future commodity prices and royalty regimes; availability of skilled labour; timing and amount of capital expenditures; future
exchange rates; the impact of increasing competition; conditions in general economic and financial markets; availability of drilling and related equipment
and services; effects of regulation by governmental agencies; and future operating costs. Management has included the above summary of assumptions
and risks related to forward-looking information provided in this MD&A in order to provide shareholders with a more complete perspective on Petrus’
future operations and such information may not be appropriate for other purposes. Petrus’ 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.
Readers are cautioned that the foregoing lists of factors are not exhaustive.
These forward-looking statements are made as of the date of this MD&A and the Company disclaims any intent or obligation to update any forward-
looking statements, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws.
BOE Presentation
The oil and natural gas industry commonly expresses production volumes and reserves on a barrel of oil equivalent (“boe”) basis whereby natural gas
volumes are converted at the ratio of six thousand cubic feet to one barrel of oil. The intention is to sum oil and natural gas measurement units into
one basis for improved measurement of results and comparisons with other industry participants. Petrus uses the 6:1 boe measure which is the
approximate energy equivalence of the two commodities at the burner tip. Boe’s do not represent an economic value equivalence at the wellhead
and therefore may be a misleading measure if used in isolation.
Page |21
Abbreviations
$000’s
$/bbl
$/boe
$/GJ
$/mcf
bbl
bbl/d
boe
mboe
mmboe
boe/d
GJ
GJ/d
mcf
mcf/d
mmcf/d
NGLs
WTI
thousand dollars
dollars per barrel
dollars per barrel of oil equivalent
dollars per gigajoule
dollars per thousand cubic feet
barrel
barrels per day
barrel of oil equivalent
barrel of oil equivalent
thousand barrel of oil equivalent
million barrel of oil equivalent per day
gigajoule
gigajoules per day
thousand cubic feet
thousand cubic feet per day
million cubic feet per day
natural gas liquids
West Texas Intermediate
Page |22
CONSOLIDATED ANNUAL FINANCIAL STATEMENTS
As at and for the years ended December 31, 2018 and 2017
INDEPENDENT AUDITORS’ REPORT
To the Shareholders of Petrus Resources Ltd.
Opinion
We have audited the consolidated financial statements of Petrus Resources Ltd. (the Company), which comprise the consolidated balance sheets as at December
31, 2018 and 2017, and the consolidated statements of net loss and comprehensive loss, consolidated statements of changes in shareholders’ equity and
consolidated statements of cash flows for the years then ended, and notes to the consolidated financial statements, including a summary of significant accounting
policies.
In our opinion, the accompanying consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company
as at December 31, 2018 and 2017, and its consolidated financial performance and its consolidated cash flows for the years then ended in accordance with
International Financial Reporting Standards (IFRSs).
Basis for Opinion
We conducted our audit in accordance with Canadian generally accepted auditing standards. Our responsibilities under those standards are further described
in the Auditor’s Responsibilities for the Audit of the Consolidated Financial Statements section of our report. We are independent of the Company in accordance
with the ethical requirements that are relevant to our audit of the consolidated financial statements in Canada, and we have fulfilled our other ethical
responsibilities in accordance with these requirements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis
for our opinion.
Other Information
Management is responsible for the other information. The other information comprises:
• Management’s Discussion and Analysis
•
Annual Report
Our opinion on the consolidated financial statements does not cover the other information and we do not express any form of assurance conclusion thereon.
In connection with our audit of the consolidated financial statements, our responsibility is to read the other information, and in doing so, consider whether
the other information is materially inconsistent with the consolidated financial statements or our knowledge obtained in the audit or otherwise appears to be
materially misstated.
We obtained Management’s Discussion & Analysis prior to the date of this auditor’s report. If, based on the work we have performed, we conclude that there
is a material misstatement of this other information, we are required to report that fact. We have nothing to report in this regard.
We obtained the Annual Report prior to the date of this auditor’s report. If, based on the work we have performed, we conclude that there is a material
misstatement of this other information, we are required to report that fact. We have nothing to report in this regard.
Responsibilities of Management and Those Charged with Governance for the Consolidated Financial Statements
Management is responsible for the preparation and fair presentation of the consolidated financial statements in accordance with IFRSs, 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.
In preparing the consolidated financial statements, management is responsible for assessing the Company’s ability to continue as a going concern, disclosing,
as applicable, matters related to going concern and using the going concern basis of accounting unless management either intends to liquidate the Company
or to cease operations, or has no realistic alternative but to do so.
Those charged with governance are responsible for overseeing the Company’s financial reporting process.
Auditor’s Responsibilities for the Audit of the Consolidated Financial Statements
Our objectives are to obtain reasonable assurance about whether the consolidated financial statements as a whole are free from material misstatement, whether
due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that
an audit conducted in accordance with Canadian generally accepted auditing standards will always detect a material misstatement when it exists. Misstatements
can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic
decisions of users taken on the basis of these consolidated financial statements.
As part of an audit in accordance with Canadian generally accepted auditing standards, we exercise professional judgment and maintain professional skepticism
throughout the audit. We also:
•
Identify and assess the risks of material misstatement of the consolidated financial statements, whether due to fraud or error, design and perform
audit procedures responsive to those risks, and obtain audit evidence that is sufficient and appropriate to provide a basis for our opinion. The risk
of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery,
intentional omissions, misrepresentations, or the override of internal control.
•
•
•
•
Obtain an understanding of internal control relevant to the audit 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 Company’s internal control.
Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related disclosures made by
management.
Conclude on the appropriateness of management’s use of the going concern basis of accounting and, based on the audit evidence obtained, whether
a material uncertainty exists related to events or conditions that may cast significant doubt on the Company’s ability to continue as a going concern.
If we conclude that a material uncertainty exists, we are required to draw attention in our auditor’s report to the related disclosures in the consolidated
financial statements or, if such disclosures are inadequate, to modify our opinion. Our conclusions are based on the audit evidence obtained up to
the date of our auditor’s report. However, future events or conditions may cause the Company to cease to continue as a going concern.
Evaluate the overall presentation, structure and content of the consolidated financial statements, including the disclosures, and whether the
consolidated financial statements represent the underlying transactions and events in a manner that achieves fair presentation.
We communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit and significant audit findings,
including any significant deficiencies in internal control that we identify during our audit.
We also provide those charged with governance with a statement that we have complied with relevant ethical requirements regarding independence, and to
communicate with them all relationships and other matters that may reasonably be thought to bear on our independence, and where applicable, related
safeguards.
The engagement partner on the audit resulting in this independent auditor’s report is Janet Huang.
Calgary, Alberta
March 13, 2019
CONSOLIDATED BALANCE SHEETS
(Presented in 000’s of Canadian dollars)
As at
December 31, 2018
December 31, 2017
ASSETS
Current
Cash
Deposits and prepaid expenses
Accounts receivable (note 15)
Risk management asset (note 10)
Total current assets
Non-current
Risk management asset (note 10)
Exploration and evaluation assets (notes 5 and 6)
Property, plant and equipment (notes 5 and 7)
Total assets
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Bank indebtedness (note 15)
Accounts payable and accrued liabilities (note 15)
Total current liabilities
Non-current liabilities
Long term debt (note 8)
Decommissioning obligation (note 9)
Risk management liability (note 10)
Total liabilities
Shareholders’ equity
Share capital (note 11)
Contributed surplus
Deficit
Total shareholders' equity
Total liabilities and shareholders' equity
Commitments (note 19)
See accompanying notes to the consolidated financial statements
Approved by the Board of Directors,
(signed) “Don T. Gray”
Don T. Gray
Chairman
63
1,297
12,675
6,786
20,821
2,749
42,410
275,840
341,820
380
21,646
22,026
131,422
40,224
—
193,672
430,119
8,384
(290,355)
148,148
341,820
24
1,430
11,588
2,163
15,205
572
43,197
294,471
353,445
3,844
25,601
29,445
131,907
40,654
711
202,717
430,119
7,680
(287,071)
150,728
353,445
(signed) “Donald Cormack”
Donald Cormack
Director
Page |26
CONSOLIDATED STATEMENTS OF NET LOSS AND COMPREHENSIVE LOSS
(Presented in 000’s of Canadian dollars, except per share amounts)
Year ended
December 31, 2018
Year ended
December 31, 2017
REVENUE
Oil and natural gas revenue (note 21)
Royalty expense
Net oil and natural gas revenue
Other income
Net gain on financial derivatives (note 10)
EXPENSES
Operating (note 13)
Transportation
General and administrative (note 14)
Share-based compensation (note 11)
Finance (note 17)
Exploration and evaluation (note 6)
Depletion and depreciation (note 7)
Loss (gain) on sale of assets (note 5)
Impairment (notes 6 and 7)
Total expenses
NET LOSS AND COMPREHENSIVE LOSS
Net loss per common share
Basic and diluted (note 12)
See accompanying notes to the consolidated financial statements
80,716
(11,638)
69,078
440
4,549
74,067
15,652
3,789
5,184
576
9,797
1,938
40,423
(8)
—
77,351
(3,284)
$
(0.07) $
90,569
(13,270)
77,299
—
13,353
90,652
18,950
4,880
3,252
503
8,389
2,783
52,614
1,542
109,000
201,913
(111,261)
(2.28)
Page |27
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Presented in 000’s of Canadian dollars)
Balance, December 31, 2016
Net loss
Issuance of common shares
Share issue costs
Share-based compensation
Balance, December 31, 2017
Net loss
Share-based compensation
Balance, December 31, 2018
See accompanying notes to the consolidated financial statements
Share
Capital
419,672
—
10,498
(51)
—
430,119
—
—
430,119
Contributed
Surplus
7,409
—
(96)
—
367
7,680
—
704
8,384
Deficit
(175,810)
(111,261)
—
—
—
(287,071)
(3,284)
—
(290,355)
Total
251,271
(111,261)
10,402
(51)
367
150,728
(3,284)
704
148,148
Page |28
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Presented in 000’s of Canadian dollars)
OPERATING ACTIVITIES
Net loss
Adjust items not affecting cash:
Share-based compensation (note 11)
Unrealized gain on financial derivatives (note 10)
Non-cash finance expenses (note 17)
Depletion and depreciation (note 7)
Impairment (notes 6 and 7)
Exploration and evaluation expense (note 6)
Loss (gain) on sale of assets (note 5)
Decommissioning expenditures (note 9)
Funds flow
Change in operating non-cash working capital (note 18)
Cash flows from operating activities
FINANCING ACTIVITIES
Issue of common shares (note 11)
Share issue costs (note 11)
Repayment of term loan
Increase (repayment) of revolving credit facility
Increase (repayment) in bank indebtedness
Transaction costs on debt
Change in financing non-cash working capital (note 18)
Cash flows from (used in) financing activities
INVESTING ACTIVITIES
Property and equipment acquisitions (note 5)
Property and equipment dispositions (note 5)
Exploration and evaluation asset acquisitions (note 5)
Exploration and evaluation asset expenditures (note 6)
Petroleum and natural gas property expenditures (note 7)
Other capital expenditures (note 7)
Change in investing non-cash working capital (note 18)
Cash flows (used in) investing activities
Increase (decrease) in cash
Cash, beginning of year
Cash, end of year
Cash interest paid
See accompanying notes to the consolidated financial statements
Page |29
Year ended
December 31, 2018
Year ended
December 31, 2017
(3,284)
576
(7,510)
1,524
40,423
—
1,938
(8)
(475)
33,184
(4,764)
28,420
—
—
—
(600)
(3,464)
(350)
298
(4,116)
(285)
50
(92)
(1,486)
(21,777)
(60)
(615)
(24,265)
39
24
63
8,272
(111,261)
503
(9,621)
1,395
52,614
109,000
2,783
1,542
(1,952)
45,003
931
45,934
10,429
(51)
(7,000)
23,833
3,844
(1,541)
(847)
28,667
(1,770)
4,837
(8,000)
(829)
(71,723)
(198)
2,826
(74,857)
(256)
280
24
6,992
NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
For the years ended December 31, 2018 and 2017
1. NATURE OF THE ORGANIZATION
Petrus Resources Ltd. (the “Company” or "Petrus") was incorporated under the laws of the Province of Alberta on November 25, 2015. The principal undertaking
of Petrus is the investment in energy business-related assets. The operations of the Company consistof the acquisition, development, exploration and exploitation
of these assets. These consolidated financial statements reflect only the Company’s proportionate interest in such activities and are comprised of the Company
and its subsidiaries, Petrus Resources Corp. and Petrus Resources Inc.
The Company’s head office is located at 2400, 240 - 4th Avenue SW, Calgary, Alberta, Canada.
These consolidated financial statements, for the years ended December 31, 2018 and 2017, were approved by the Company’s Audit Committee and Board of
Directors on March 13, 2019.
2. BASIS OF PRESENTATION
Statement of Compliance
(a) Statement of Compliance
These consolidated financial statements have been prepared by management in accordance with International Financial Reporting Standards (“IFRS”) as
issued by the International Accounting Standards Board (“IASB”).
(b) Measurement Basis
These consolidated financial statements were prepared on the basis of historical cost except for financial derivatives which are measured at fair value.
This method is consistent with the method used in prior years. These consolidated financial statements are presented in Canadian dollars.
(c) Consolidation
These audited consolidated financial statements include the accounts of Petrus and its 100% owned subsidiaries, Petrus Resources Corp. and Petrus
Resources Inc. Subsidiaries are consolidated from the date control is obtained until the date control ends. Control exists where the Company has power
over the investee, exposure or rights to variable returns from the investee and the ability to use its power over the investee to affect returns. All intra-
group balances and transactions are eliminated on consolidation.
(d) Critical Accounting Estimates
The timely preparation of financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect
the application of accounting policies and reported amounts of assets and liabilities and income and expenses. Accordingly, actual results may differ from
these estimates. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period
in which the estimates are revised and in any future periods affected. Significant estimates and judgments made by management in the preparation of
the financial statements are outlined below.
Depletion and reserve estimates
Petroleum and natural gas assets are depleted on a unit of production basis at a rate calculated by reference to proved and probable reserves
determined in accordance with National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). The calculation
incorporates the estimated future cost of developing and extracting those reserves. Proved and probable reserves are estimated using independent
reservoir engineering reports 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. Reserves estimates, although not reported as part of the Company’s financial statements, can have a significant
effect on net income (loss), assets and liabilities as a result of their impact on depletion and depreciation, decommissioning liabilities, deferred taxes,
asset impairments and business combinations. Independent reservoir engineers perform evaluations of the Company’s petroleum and natural gas
reserves on an annual basis. The estimation of reserves is an inherently complex process requiring significant judgment. Estimates of economically
recoverable petroleum and natural gas reserves are based upon a number ofvariables and assumptions such as geoscientific interpretation, production
forecasts, commodity prices, costs and related future cash flows, all of which may vary considerably from actual results. These estimates are expected
to be revised upward or downward over time, as additional information such as reservoir performance becomes available or as economic conditions
change.
Impairment indicators and cash-generating units
For purposes of impairment testing, exploration and evaluation assets and petroleum and natural gas assets are aggregated into cash-generating
units (“CGUs”), based on separately identifiable and largely independent cash inflows. The determination of the Company’s CGUs is subject to
judgment.
The recoverable amounts of CGU’s and individual assets have been determined based on the higher of the value-in-use calculations and fair value
less costs of disposal. These calculations require the use of estimates and assumptions, including the discount rate, future petroleum and natural
Page |30
gas prices, expected production volumes and anticipated recoverable quantities of proved and probable reserves. These assumptions are subject
to change as new information becomes available and changes in economic conditions take place. Changes may impact the estimated life of the
field and economical reserves recoverable and may require a material adjustment to the carrying value of exploration and evaluation assets and
petroleum and natural gas assets. The Company monitors internal and external indicators of impairment relating to its tangible assets.
Technical feasibility and commercial viability of exploration and evaluation assets
The determination of technical feasibility and commercial viability, based on the presence of proved and probable reserves, results in the transfer
of assets from exploration and evaluation assets to property, plant and equipment. As discussed above, the estimate of proved and probable reserves
is inherently complex and requires significant judgment. Thus any material change to reserve estimates could affect the technical feasibility and
commercial viability of the underlying assets.
Financial Instruments
Financial instruments are subject to valuations at the end of each reporting period. Generally the valuation is based on active and efficient markets.
However, certain financial instruments may not be traded on an efficient market or the market may disappear or be subject to conditions that impede
the efficiency of the market.
Decommissioning obligation
At the end of the operating life of the Company’s facilities and properties and upon retirement of its petroleum and natural gas assets,
decommissioning costs will be incurred by the Company. This requires judgment regarding abandonment date, future environmental and regulatory
legislation, the extent of reclamation activities, the engineering methodology for estimating cost, future removal technologies in determining the
removal cost and discount rates to determine the present value of these cash flows.
Income taxes
Tax provisions are based on enacted or substantively enacted laws. Changes in those laws could affect amounts recognized in income or loss both
in the period of change, which would include any impact on cumulative provisions, and in future periods. Changes in tax laws in the jurisdictions
in which the Company operates could limit the ability of the Company to obtain tax deductions in future periods. Income taxes are subject to
measurement uncertainty. Significant judgment can be involved in the recognition of deferred tax assets.
Measurement of share-based compensation
Share-based compensation recorded pursuant to share-based compensation plans are subject to estimated fair values, forfeiture rates and the
future attainment of performance criteria.
Business combinations
Business combinations are accounted for using the acquisition method of accounting. The determination of fair value often requires management
to make assumptions and estimates about future events. The assumptions and estimates with respect to determining the fair value of exploration
and evaluation assets and petroleum and natural gas assets acquired generally require the most judgment and include estimates of reserves acquired,
forecast benchmark commodity prices and discount rates. Changes in any of the assumptions or estimates used in determining the fair value of
acquired assets and liabilities could impact the amounts assigned to assets, liabilities and goodwill in the purchase price allocation.
Contingencies
By their nature, contingencies will only be resolved when one or more future events occur or fail to occur. The assessment of contingencies inherently
involves the exercise of significant judgment and estimates of the outcome of future events.
3. SIGNIFICANT ACCOUNTING POLICIES
(a) Revenue recognition
Revenue from contracts with customers is recognized when or as Petrus satisfies a performance obligation by transferring a promised good or service to
a customer. The transfer of control of oil, natural gas, natural gas liquids usually occurs at a point in time and coincides with title passing to the customer
and the customer taking physical possession. The transaction price for variable price contracts is based on the commodity price, adjusted for quality,
location and other factors. The amount of revenue recognized is based on the agreed transaction price with any variability in transaction price recognized
in the same period.
(b) Exploration & evaluation assets
Capitalization
All costs incurred after the rights to explore an area have been obtained, such as geological and geophysical costs, other direct costs of exploration
(drilling, testing and evaluating the technical feasibility and commercial viability of extraction) and appraisal and including any directly attributable
general and administration costs and share-based payments, are accumulated and capitalized as exploration and evaluation assets.
Certain costs incurred prior to acquiring the legal rights to explore are charged directly to net income (loss).
Page |31
Depletion & depreciation
Exploration and evaluation costs are not amortized prior to the conclusion of appraisal activities. At the completion of appraisal activities, if technical
feasibility is demonstrated and commercial reserves are discovered, then the carrying value of the relevant exploration and evaluation asset will be
reclassified as a property, plant and equipment asset into the CGU to which it relates, but only after the carrying value of the relevant exploration
and evaluation asset has been assessed for impairment and, where appropriate, its carrying value adjusted. Technical feasibility and commercial
viability are considered to be demonstrable when proved or probable reserves are determined to exist. If it is determined that technical feasibility
and commercial viability have not been achieved in relation to the exploration and evaluation assets appraised, all other associated costs are written
down to the recoverable amount in net income (loss).
Expired land leases included as undeveloped land in exploration and evaluation assets are recognized in exploration and evaluation cost in net income
(loss) upon expiry and are considered prior to expiry. Management considers upcoming land lease expiries and may recognize the costs in advance
of expiry.
Impairment
Indicators of impairment of exploration and evaluation assets are assessed at each reporting date which can include upcoming land lease expiries,
third party land valuations and other information . When there are such indications, an impairment test is carried out and any resulting impairment
loss is written off to net income (loss). The recoverable amount is the greater of fair value, less costs of disposal, or value-in-use.
(c) Property, plant and equipment
The Company’s property, plant and equipment is comprised of petroleum and natural gas assets and corporate assets.
Capitalization
Petroleum and natural gas assets are measured at cost less accumulated depletion and depreciation and accumulated impairment losses, if any.
Petroleum and natural gas assets consists of the purchase price and costs directly attributable to bringing the asset to the location and condition
necessary for its intended use. Petroleum and natural gas assets include developing and producing interests such as land acquisitions, geological and
geophysical costs, facility and production equipment, including any directly attributable general and administration costs and share-based payments
and the initial estimate of the costs of dismantling and removing an asset and restoring the site on which it was located.
Subsequent costs
Costs incurred subsequent to the determination of technical feasibility and commercial viability are recognized as developing and producing petroleum
and natural gas interests when they increase the future economic benefits embodied in the specific asset to which they relate. Such capitalized
petroleum and natural gas interests generally represent costs incurred in developing proved and/or probable reserves, and are accumulated on a
field or geotechnical area basis. The cost of day-to-day servicing of an item of petroleum and natural gas assets is expensed in income or loss as
incurred. Petroleum and natural gas assets are derecognized upon disposal or when no future economic benefits are expected to arise from the
continued use of the asset. Any gain or loss arising from the disposal of an asset, determined as the difference between the net disposal proceeds
and the carrying amount of the asset, is recognized in net income or loss.
Depletion and depreciation
The costs for petroleum and natural gas properties, including related pipelines and facilities, are depleted using a unit-of-production method based
on the commercial proved and probable reserves.
Petroleum and natural gas assets are not depleted until production commences. This depletion calculation includes actual production in the period
and total estimated proved and probable reserves attributable to the assets being depleted, taking into account total capitalized costs plus estimated
future development costs necessary to bring those reserves into production. Relative volumes of reserves and production (before royalties) are
converted at the energy equivalent conversion ratio of six thousand cubic feet of natural gas to one barrel of oil.
Proved and probable reserves are estimated using independent reservoir engineering reports 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.
Corporate assets are recorded at cost less accumulated depreciation. Depreciation is calculated on a declining balance method so as to write off the
cost of these assets, less estimated residual values, over their estimated useful lives consistent with the treatment used for tax purposes.
Impairment
The assessment for impairment entails comparing the carrying value of the CGU with its recoverable amount: that is, the higher of fair value, less
costs of disposal, and value in use. Petrus’ property, plant and equipment are grouped into CGUs based on separately identifiable and largely
independent cash inflows considering geological characteristics, shared infrastructure and exposure to market risks. Estimates of future cash flows
used in the calculation of the recoverable amount are based on reserve evaluation reports prepared by independent reservoir engineers.
The CGU’s are reviewed quarterly for indicators of impairment. Indicators are events or changes in circumstances that indicate that the carrying
amount may not be recoverable. If indicators of impairment exist, the recoverable amount of the CGU is estimated. If the carrying amount of the
CGU exceeds the recoverable amount, the CGU is written down with an impairment recognized in net income (loss).
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The recoverable amount is the higher of fair value, less costs of disposal, and the value-in-use. Fair value, less costs of disposal, is derived by estimating
the discounted after-tax future net cash flows. Discounted future net cash flows are based on forecasted commodity prices and costs over the
expected economic life of the reserves and discounted using market-based rates to reflect a market participant’s view of the risks associated with
the assets. Value-in-use is assessed using the expected future cash flows discounted at a pre-tax rate.
Impairments of property, plant and equipment are reversed when there is significant evidence that the impairment has been reversed, but only to
the extent of what the carrying amount would have been had no impairment been recognized.
(d) Business combinations
Business combinations are accounted for using the acquisition method. Identifiable assets acquired and liabilities and contingent liabilities assumed in a
business combination are measured at their fair values at the acquisition date. 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 acquisition date. The excess of the cost of the acquisition over the fair value of the
identifiable assets, liabilities and contingent liabilities acquired is recorded as goodwill. If the cost of the acquisition is less than the fair value of the net
assets of the subsidiary acquired, the difference is recognized immediately in net income (loss). Transaction costs associated with a business combination
are expensed as incurred.
(e) Decommissioning obligations
The Company’s activities give rise to dismantling, decommissioning and reclamation requirements. Costs related to these abandonment activities are
estimated by management in consultation with the Company’s engineers based on risk-adjusted current costs which take into consideration current
technology in accordance with existing legislation and industry practices.
Decommissioning obligations are measured at the present value of the best estimate of expenditures required to settle the obligations at the reporting
date. When the fair value of the liability is initially measured, the estimated cost, discounted using a risk-free rate, is capitalized by increasing the carrying
amount of the related petroleum and natural gas assets. The increase in the provision due to the passage of time, or accretion, is recognized as a finance
expense. Increases and decreases due to revisions in the estimated future cash flows are recorded as adjustments to the carrying amount of the related
petroleum and natural gas assets.
Actual costs incurred upon settlement of the liability are charged against the obligation to the extent that the obligation was previously established. The
carrying amount capitalized in petroleum and natural gas assets is depleted in accordance with the Company’s depletion policy. The Company reviews the
obligation at each reporting date and revisions to the estimated timing of cash flows, discount rates and estimated costs will result in an increase or decrease
to the obligations. Any difference between the actual costs incurred upon settlement of the obligation and recorded liability is recognized as an increase
or reduction in income.
(f) Finance expenses
Finance expense may be comprised of interest expense on borrowings, acquisition related (transaction) costs, foreign exchange expenses and accretion of
the discount on decommissioning obligations.
(g) Financial instruments
Financial instruments are recognized initially at fair value plus any directly attributable transaction costs. Subsequent to initial recognition, financial
instruments are measured based on their classification as described below:
•
•
Fair value through profit or loss: Financial instruments under this classification include risk management assets and liabilities.
Amortized cost: Financial instruments under this classification include cash, accounts receivable, deposits, bank indebtedness, accounts payable
and long term debt.
(h) Share capital
Common shares are classified as equity. Incremental costs directly attributable to the issuance of common shares are recognized as a reduction in share
capital, net of any tax effects.
(i) Flow-through shares
The resources expenditure deductions for income tax purposes related to exploratory activities funded by flow-through shares are renounced to investors
in accordance with tax legislation. Upon issuance of a flow-through share, a liability is recognized representing the premium paid on flow-through common
shares over regular common shares. This liability is reduced as the expenditures are incurred and tax attributes are renounced.
(j) Income taxes
The Company’s income tax expense is comprised of current and deferred tax. Income tax expense is recognized through income or loss except to the extent
that it relates to items recognized directly in equity, in which case the related income taxes are also recognized in equity.
Current tax is the expected tax payable on taxable income for the period, using tax rates enacted or substantively enacted at the reporting date, and any
adjustment to tax payable in respect of previous years.
Deferred tax is recognized on temporary differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding
tax basis used in the computation of taxable income. Deferred tax liabilities are generally recognized for all taxable temporary differences. Deferred tax
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assets are generally recognized for all deductible temporary differences to the extent that it is probable that taxable income will be available against which
those deductible temporary differences can be utilized. Assessing the recoverability of deferred tax assets requires management to make significant estimates
related to expectations of future taxable income. Estimates of future taxable income are based on forecast cash flows from operations and the application
of existing tax laws in the jurisdictions of Alberta and Canada. The carrying amount of deferred tax assets is reviewed at the end of each reporting period
and reduced to the extent that it is no longer probable that sufficient taxable income will be available to allow all or part of the asset to be recovered.
(k) Joint arrangements
A portion of the Company’s exploration, development and production activities are conducted jointly with others through unincorporated joint operations.
These financial statements reflect only the Company’s proportionate interest of these joint operations and the proportionate share of the relevant revenue
and related costs.
(l) Share-based compensation
Share-based compensation expense is determined based on the estimated fair value of shares on the date of grant. Forfeitures are estimated at the grant
date and are subsequently adjusted to reflect actual forfeitures. The expense is recognized over the service period, with a corresponding increase to
contributed surplus. The Company capitalizes the qualifying portion of share-based compensation expense directly attributable to the exploration and
development activities of exploration and evaluation assets and petroleum and natural gas assets, with a corresponding decrease to share-based
compensation expense. At the time the stock options or performance warrants are exercised, the issuance of common shares is recorded as an increase
to shareholders’ capital and a corresponding decrease to contributed surplus.
For deferred share units (“DSUs”) that can be settled in cash or equity at the option of the DSU participants, the fair value of the DSUs is recognized as
stock-based compensation expense, with a corresponding increase in accrued liabilities. DSUs are measured at their fair value at each reporting period on
a mark-to-market basis.
(m) Earnings per share
Earnings per share are presented for basic and diluted earnings. Basic per share information is computed by dividing the net income (loss) for the period
attributable to equity owners of the Company by the weighted average number of common shares outstanding during the period. The weighted average
number of shares for diluted earnings per share information is calculated using the treasury stock method whereby it is assumed that proceeds obtained
upon exercise of performance warrants and stock options would be used to purchase common shares at the average market price during the period. The
treasury stock method also assumes that the deemed proceeds related to unrecognized share-based payments expense are used to repurchase shares at
the average market price during the period. Under the treasury stock method, stock options and share warrants have a dilutive effect only when the average
market price of the common shares during the period exceeds the exercise price of the options or warrants (they are "in-the-money"). Exercise of in-the-
money stock options and share warrants is assumed at the beginning of the year or date of issuance, if later. Should the Company have a loss for the period,
stock options and share warrants would be anti-dilutive and therefore will have no effect on the determination of loss per share.
(n) Leases
The determination of whether an arrangement is, or contains a lease is based on the substance of the arrangement at the inception date, whether
fulfillment of the arrangement is dependent on the use of a specific asset or the arrangement conveys a right to use an asset. Leases which transfer
substantially all the risks and benefits of ownership to the Company are classified as finance leases. The leased asset is recognized at the lower of the
fair value of the leased property or the present value of the minimum lease payments. Finance lease assets are depreciated over the shorter of the
estimated useful life of the asset or the lease term. Other leases are classified as operating leases and payments are amortized on a straight-line basis
over the lease term.
(o) New standards and interpretations
IFRS 9 - Financial Instruments
On January 1, 2018, Petrus adopted IFRS 9 Financial Instruments, which includes a principle-based approach for classification and measurement of financial
assets and a forward-looking ‘expected credit loss’ model. The classification and measurement of financial instruments under IFRS 9 did not have a material
impact on Petrus’ consolidated financial statements. In addition, the application of the expected credit loss model to financial assets classified as amortized
cost did not result in a material adjustment on transition. IFRS 9 was applied retrospectively in accordance with transition requirements with no impact
to opening retained earnings or comparative periods.
IFRS 15 - Revenue from Contracts with Customers
Petrus adopted IFRS 15 "Revenue from Contracts with Customers" effective January 1, 2018, which establishes a comprehensive framework for determining
whether, how much, and when revenue from contracts with customers is recognized. Petrus' revenue relates to the sale of petroleum and natural gas to
customers at specified delivery points at benchmark prices. Petrus adopted IFRS 15 using the modified retrospective approach. Under this transitional
provision, the cumulative effect of initially applying IFRS 15 is recognized on the date of initial application as an adjustment to retained earnings. No
adjustment to retained earnings was required upon adoption of IFRS 15. The adoption of IFRS 15 did not materially impact the timing or measurement of
revenue. However, IFRS 15 contains new disclosure requirements.
IFRS 16 - Leases
IFRS 16 was issued in January 2016 and it replaces IAS 17 Leases, IFRIC 4 Determining whether an Arrangement contains a Lease, SIC-15 Operating Leases-
Incentives and SIC-27 Evaluating the Substance of Transactions Involving the Legal Form of a Lease. IFRS 16 sets out the principles for the recognition,
measurement, presentation and disclosure of leases and requires lessees to account for all leases under a single on-balance sheet model similar to the
accounting for finance leases under IAS 17. The standard includes two recognition exemptions for lessees – leases of ’low-value’ assets (e.g., personal
Page |34
computers) and short-term leases (i.e., leases with a lease term of 12 months or less). At the commencement date of a lease, a lessee will recognize a
liability to make lease payments (i.e., the lease liability) and an asset representing the right to use the underlying asset during the lease term (i.e., the right-
of-use asset). Lessees will be required to separately recognize the interest expense on the lease liability and the depreciation expense on the right-of-use
asset.
Lessees will be also required to remeasure the lease liability upon the occurrence of certain events (e.g., a change in the lease term, a change in future
lease payments resulting from a change in an index or rate used to determine those payments). The lessee will generally recognize the amount of the
remeasurement of the lease liability as an adjustment to the right-of-use asset.
IFRS 16 is effective for annual periods beginning on or after January 1, 2019. A lessee can choose to apply the standard using either a full retrospective or
a modified retrospective approach. The standard’s transition provisions permit certain reliefs. Petrus is finalizing its review of identified leases and
arrangements qualifying as leases under IFRS 16 and is in the process of determining the financial impact of identified leases on its consolidated financial
statements. Petrus expects to adopt IFRS 16 using the modified retrospective approach.
On initial adoption, the Company expects to use the following practical expedients permitted under the standard:
1.
2.
3.
4.
Apply a single discount rate to a portfolio of leases with similar characteristics;
Account for leases with a remaining term of less than 12 months as at January 1, 2019 as short-term leases;
Account for lease payments as an expense and not recognize a right-of-use (“ROU”) asset if the underlying asset is of low dollar value;
The use of hindsight in determining the lease term where the contract contains terms to extend or terminate the lease; and
The Company has identified ROU assets and lease liabilities primarily related to office space. The Company has completed an initial assessment but not
yet finalized the potential impact on its consolidated financial statements.
4. 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.
Petroleum and natural gas properties and equipment and exploration and evaluation assets
The fair value of petroleum and natural gas properties and equipment recognized in a business combination and for impairment testing, is based on
market values. The market value of petroleum and natural gas properties and equipment is the estimated amount for which property, plant and
equipment 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 market value of oil and natural gas interests
(included in petroleum and natural gas properties and equipment) and intangible exploration and evaluation assets is estimated with reference to
the discounted cash flow expected to be derived from 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. The fair value less costs of disposal value used to determine the
recoverable amount of the impaired petroleum and natural gas properties are classified as Level 3 fair value measurements. Refer to “Financial
Instruments” section below for fair value hierarchy classifications.
Derivatives
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 balance sheet date, using the remaining contracted oil and natural gas volumes and a risk-free interest rate (based on
published government rates). The fair value of options is based on option models that use published information with respect to volatility, prices,
interest rates and counter-party credit risks.
Share-based payments
The fair value of employee share-based payments is measured using a Black-Scholes option-pricing model. Measurement inputs include share price
on measurement date, exercise price of the instrument, expected volatility in share price (based on weighted average historic volatility adjusted for
changes expected due to publicly available information), weighted average expected life of the instruments (based on historical experience and
general option holder behavior), expected dividend yield, risk-free interest rate (based on government bonds) and estimated forfeiture rate at each
reporting date.
Financial Instruments
The Company’s fair value measurements require disclosure about how the fair value was determined based on significant levels of inputs described
in the following hierarchy:
•
•
Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those
in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 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.
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•
Level 3 - Valuations in this level are those with inputs for the asset or liability that are not based on observable market data.
Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair
value hierarchy level. The Company’s risk management contracts are considered Level 2.
5. ACQUISITIONS AND DISPOSITIONS
Asset exchange agreement
On March 13, 2018, Petrus closed a property swap transaction to exchange assets with an arm's length party. The Company recorded a loss of $0.1 million on
the asset exchange, net of closing adjustments, during the year ended December 31, 2018.
The following tables summarize the net assets disposed of and acquired pursuant to the swap:
Net assets disposed $000s
Exploration and evaluation assets ("E&E assets")
Petroleum and natural gas properties and equipment ("PP&E")
Decommissioning obligations
Total net assets disposed
Fair value of net assets acquired $000s
Exploration and evaluation assets
Petroleum and natural gas properties and equipment
Decommissioning obligations
Total net assets acquired
1,086
3,231
(471)
3,846
1,013
2,852
(224)
3,641
During the year ended December 31, 2018, Petrus incurred approximately $0.2 million in net cash expenditures on other minor acquisition and disposition
transactions for E&E assets and PP&E. During the year ended December 31, 2018, the Company recorded a net gain of $0.1 million, net of approximately $0.1
in decommissioning obligation, from the disposition of E&E assets and PP&E for cash proceeds of approximately $0.4 million.
Property disposition - non-core
On August 15, 2017 Petrus closed the disposition of its working interest in certain non-core oil and natural gas properties in the Company’s Foothills area for
cash consideration of $4.8 million. The assets disposed of included approximately 150 boe/d of production along with related land and infrastructure. The
proceeds were utilized to repay indebtedness under the Company’s credit facilities. The Company recorded a loss of $1.0 million related to the disposition.
The following table summarizes the net assets disposed pursuant to the disposition:
Net assets disposed $000s
Exploration and evaluation assets
Petroleum and natural gas properties and equipment
Decommissioning obligations
Total net assets disposed
1,438
5,579
(1,232)
5,785
Property acquisition
On February 28, 2017 Petrus closed the acquisition of oil and natural gas assets for total cash consideration of $8.8 million net of closing adjustments. The
acquisition included approximately 3,200 undeveloped Cardium leases in is Ferrier core area, approximately 40 boe/d of production and a non-producing well.
The purchase price was allocated as follows:
Fair value of net assets acquired $000s
Exploration and evaluation assets
Petroleum and natural gas properties and equipment
Decommissioning obligations
Total net assets acquired
8,000
969
(151)
8,818
Other acquisition and disposition activity
During 2017, Petrus recorded other minor acquisition and disposition transactions for petroleum and natural gas properties and equipment for total net cash
consideration of $0.8 million.
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6. EXPLORATION AND EVALUATION ASSETS
The components of the Company’s exploration and evaluation assets are as follows:
$000s
Balance, December 31, 2016
Additions
Property acquisitions (note 5)
Exploration and evaluation expense
Capitalized G&A
Capitalized share-based compensation
Property disposition (note 5)
Transfers to property, plant and equipment (note 7)
Impairment loss
Balance, December 31, 2017
Additions
Property acquisitions (note 5)
Exploration and evaluation expense
Capitalized G&A
Capitalized share-based compensation (note 11)
Property dispositions (note 5)
Transfers to property, plant and equipment (note 7)
Balance, December 31, 2018
64,824
309
8,000
(2,783)
520
75
(1,438)
(7,036)
(19,274)
43,197
1,057
402
(1,938)
429
70
(58)
(749)
42,410
For the year ended December 31, 2018, the Company incurred exploration and evaluation expense of $1.9 million, which relates to expired and near expiry
undeveloped, non-core land (2017 – $2.8 million).
During the year ended December 31, 2018, the Company capitalized $0.4 million of general and administrative expenses (“G&A”) (2017 – $0.5 million ) and
$0.07 million of non-cash share-based compensation directly attributable to exploration activities (2017 – $0.1 million).
During the year ended December 31, 2017, management determined that certain CGUs were no longer considered to be core to the Company. As such, a
process was initiated to potentially divest of the Company's Foothills and Central Alberta CGUs. Based on interest expressed in the Foothills and Central Alberta
assets and information obtained through the divestiture process to date, the Company determined there were indicators of impairment and estimated the
recoverable amounts of the Foothills exploration and evaluation assets to be $2.9 million and the Central Alberta exploration and evaluation assets to be $2.7
million as at December 31, 2017. The Company recorded an impairment loss of $19.3 million during the year ended December 31, 2017.
For the year ended December 31, 2018, Company did not identify any indicators of impairment in the Company's exploration and evaluation assets.
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7. PROPERTY, PLANT AND EQUIPMENT
The components of the Company’s property, plant and equipment assets are as follows:
$000s
Balance, December 31, 2016
Additions
Property acquisitions (note 5)
Property (dispositions) (note 5)
Capitalized G&A
Capitalized share-based compensation
Transfers from exploration and evaluation assets (note 6)
Depletion & depreciation
Decrease in decommissioning provision (note 9)
Impairment loss
Balance, December 31, 2017
Additions
Property acquisitions (note 5)
Property dispositions (note 5)
Capitalized G&A
Capitalized share-based compensation (note 11)
Transfers from exploration and evaluation assets (note 6)
Depletion & depreciation
Decrease in decommissioning provision (note 9)
Balance, December 31, 2018
Cost
714,009
70,361
1,729
(15,078)
1,560
226
7,036
—
(545)
—
779,298
20,549
2,935
(3,503)
1,288
212
749
—
(438)
801,090
Accumulated
DD&A
Net book value
(351,806)
—
—
9,320
—
—
—
(52,614)
—
(89,727)
(484,827)
—
—
—
—
—
—
(40,423)
—
(525,250)
362,203
70,361
1,729
(5,758)
1,560
226
7,036
(52,614)
(545)
(89,727)
294,471
20,549
2,935
(3,503)
1,288
212
749
(40,423)
(438)
275,840
At December 31, 2018, estimated future development costs of $291.2 million (December 31, 2017 – $283.0 million) associated with the development of the
Company’s proved plus probable undeveloped reserves were included with the costs subject to depletion. During the year ended December 31, 2018, the
Company capitalized $1.3 million of general and administrative expenses (“G&A”) (2017 – $1.6 million) and non-cash share-based compensation of $0.2 million,
respectively (2017 – $0.2 million), directly attributable to development activities.
For the year ended December 31, 2017, the Company recorded property, plant and equipment impairments of $89.7 million. At the end of the third quarter
2017, management determined that certain CGUs were no longer considered to be core to the Company. As such, a process was initiated to potentially divest
of the Company's Foothills and Central Alberta CGUs. Based on interest expressed in the Foothills and Central Alberta assets and information obtained through
the divestiture process to date, the Company determined there were indicators of impairment and estimated the recoverable amounts, net of decommissioning
liabilities, of the Foothills property plant and equipment assets to be $11.3 million and the Central Alberta property plant and equipment assets to be $44.3
million.
As at December 31, 2018, the book value of the Company's net assets was greater than its market capitalization. The Company determined there to be indicators
of impairment on the Foothills and Central Alberta CGUs and performed an impairment test on these two CGUs. No impairment charge was recorded as the
recoverable amounts were higher than their carrying values. The Company did not identify any indicators of impairment on its Ferrier CGU.
Page |38
The recoverable amounts were estimated at fair value less costs of disposal, applying an after-tax discount rate ranging from 7% to 9% on the estimated future
cashflow and the following forward commodity price estimates:
Year
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
Canadian Light Sweet
40 API $/Bbl
AECO $/MMbtu
75.27
77.89
82.25
84.79
87.39
89.14
90.92
92.74
94.60
96.49
98.42
1.95
2.44
3.00
3.21
3.30
3.39
3.49
3.58
3.68
3.78
3.88
Escalation rate of 2.0% thereafter.
8. DEBT
At December 31, 2018, Petrus had two debt instruments outstanding. The first is a reserve-based, senior secured revolving credit facility with a syndicate of
lenders, which is comprised of an operating facility and a syndicated term-out facility (together, the “Revolving Credit Facility” or “RCF”). The second is a
subordinated secured term loan (the “Term Loan”).
(a) Revolving Credit Facility
At December 31, 2018, the RCF was comprised of a $20 million operating facility and a $90 million syndicated term-out facility. Consent from
the syndicate lenders and the Term Loan lender is required for total borrowings against the RCF exceeding $105 million. The syndicated term-
out facility has a revolving period that ends May 31, 2019 at which time it will either be renewed or converted to a one-year term facility. The Company
has provided collateral by way of a debenture over all of the present and after acquired property of the Company.
At December 31, 2018, the Company had a $0.7 million letter of credit outstanding against the RCF (December 31, 2017 – $0.3 million) and had drawn
$97.0 million against the RCF (December 31, 2017 – $97.6 million).
The amount of the RCF is subject to a borrowing base review performed on a semi-annual basis by the lenders, based primarily on reserves and
commodity prices estimated by the lenders as well as other factors. In addition, asset dispositions require unanimous lender consent. A decrease in
the borrowing base could result in a reduction to the available credit under the RCF. The next scheduled borrowing base redetermination date for the
RCF is on or before May 31, 2019.
(b) Term Loan
At December 31, 2018 the Company had a $35 million (December 31, 2017 – $35 million) Term Loan outstanding (excluding $0.6 million of unamortized
deferred financing costs), which is due October 8, 2020. The Term Loan bears interest that is due and payable monthly and accrues at a per annum
rate of the (three-month) Canadian Dealer Offered Rate (CDOR) plus 700 basis points. The Company has provided collateral by way of a debenture over
all of the present and after acquired property of the Company.
Financial Covenants
The Company's RCF and Term Loan are subject to certain financial covenants. The following definitions are used in the covenant calculations for both debt
instruments:
Debt to EBITDA Ratio
Debt is defined as Petrus’ total debt outstanding of the borrower and EBITDA means earnings before interest, taxes, depreciation and amortization.
Working Capital
Working Capital means Current Assets to Current Liabilities whereby Current Assets means on any date of determination, the current assets of Petrus
that would, in accordance with IFRS, be classified as of that date as current assets plus any undrawn availability under the RCF, less any non-cash
amount required to be included in current assets as the result of the application of IFRS including non-cash commodity and interest rate hedges assets
and liabilities and whereby Current Liabilities means, on any date of determination, the liabilities of Petrus that would, in accordance with IFRS, be
classified as of that date as current liabilities, excluding (a) non-cash obligations under IFRS including non-cash commodity and interest rate hedges
assets and liabilities, and (b) the current portion of long-term debt.
Page |39
Working Capital Ratio means the ratio of Current Assets to Current Liabilities as defined above.
Proved Asset and PDP Asset Coverage Ratio
Means the ratio of (a) Total Adjusted Present Value or (b) PDP Present Value depending on the reserve category, to Total Debt
Whereby Total Adjusted or PDP reserve value means the present value (discounted at 10%) of future net revenues attributable to the respective
reserve category based on the reserve report most recently delivered to the lender.
The RCF carries the following covenants:
a.
b.
The Company is unable to borrow amounts greater than the RCF limit;
Proved Asset and PDP Asset Coverage Ratio (shown below) must be reported at each borrowing base redetermination date, using
the most current reserve report and the Net Secured Debt at the date of the annual borrowing base redetermination which will take
place on or before May 31, 2019.
The key financial covenants as at December 31, 2018 are summarized in the following table.
Financial Covenant Description
Required Ratio
As at December 31, 2018
Working Capital Ratio
Proved Asset Coverage Ratio (1)
PDP Asset Coverage Ratio (1)
Debt to EBITDA Ratio
(1) Calculations are based upon the Company's December 31, 2018 reserve report evaluated by Sproule Associates Ltd.
Over 1.00
Over 1.25
Over 1.00
Under 3.50
1.23
2.38
1.37
3.16
At December 31, 2018 the Company is in compliance with all financial covenants.
9. DECOMMISSIONING OBLIGATION
The decommissioning liability was estimated based on the Company’s net ownership interest in all wells and facilities, the estimated costs to abandon and
reclaim the wells and facilities and the estimated timing of the costs to be incurred in future periods. The estimated future cash flows have been discounted
using an average risk free rate of 2.13 percent and an inflation rate of 2.00 percent (December 31, 2017 – 2.22 percent and 2.00 percent, respectively). Changes
in estimates in 2017 and 2018 are due to the changes in the risk free rate and changes in the estimated future cash flow to reclaim the wells and facilities. The
Company has estimated the net present value of the decommissioning obligations to be $40.2 million as at December 31, 2018 ($40.7 million at December 31,
2017). The undiscounted, uninflated total future liability at December 31, 2018 is $41.6 million ($43.1 million at December 31, 2017). The payments are
expected to be incurred over the operating lives of the assets.
The following table reconciles the decommissioning liability:
$000s
Balance, December 31, 2016
Property acquisitions
Property dispositions
Liabilities incurred
Liabilities settled
Change in estimates
Accretion expense
Balance, December 31, 2017
Property acquisitions (note 3)
Property dispositions (note 3)
Liabilities incurred
Liabilities settled
Change in estimates
Accretion expense
Balance, December 31, 2018
Page |40
43,243
151
(1,232)
2,530
(1,952)
(3,075)
989
40,654
224
(629)
393
(475)
(830)
887
40,224
10. FINANCIAL RISK MANAGEMENT
The Company utilizes commodity contracts as a risk management technique to mitigate exposure to commodity price volatility. The following table
summarizes the financial derivative contracts Petrus had outstanding as at December 31, 2018:
Contract Period
Natural Gas Swaps
Jan. 1, 2019 to Mar. 31, 2019
Apr. 1, 2019 to Oct. 31, 2019
Nov. 1, 2019 to Mar. 31, 2020
Nov. 1, 2019 to Oct. 31, 2020
Contract Period
Crude Oil Swaps
Jan. 1, 2019 to Jun. 30, 2019
Jan. 1, 2019 to Mar. 31, 2019
Apr. 1, 2019 to Jun. 30, 2019
Jul. 1, 2019 to Sep. 30, 2019
Jul. 1, 2019 to Dec. 31, 2019
Oct. 1, 2019 to Dec. 31, 2019
Oct. 1, 2019 to Dec. 31, 2020
Jan. 1, 2020 to Mar. 31, 2020
Apr. 1, 2020 to Jun. 30, 2020
Jul. 1, 2020 to Sep. 30, 2020
Crude Oil Collars
Jan. 1, 2019 to Mar. 31, 2019
Risk management asset and liability:
$000s At December 31, 2018
Current commodity derivatives
Non-current commodity derivatives
$000s At December 31, 2017
Current commodity derivatives
Non-current commodity derivatives
Type
Total Daily Volume (GJ)
Average Price (CDN$/GJ)
Fixed price
Fixed price
Fixed price
Fixed price
21,000
14,000
7,000
3,500
$2.47
$1.73
$1.86
$1.58
Type
Total Daily Volume (Bbl)
Average Price (CDN$/Bbl)
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Costless collar
300
1,300
1,100
700
700
600
350
800
400
200
50
$61.60
$70.00
$68.64
$70.94
$67.59
$70.13
$76.70
$70.20
$77.11
$82.50
$60.00-69.50
Liability
—
—
—
Liability
—
711
711
Asset
6,786
2,749
9,535
Asset
2,163
572
2,735
Earnings impact of realized and unrealized gains (losses) on financial derivatives:
$000s
Realized gain (loss) on financial derivatives
Unrealized gain (loss) on financial derivatives
Net gain (loss) on financial derivatives
Year ended
Dec. 31, 2018
Year ended
Dec. 31, 2017
(2,961)
7,510
4,549
3,732
9,621
13,353
Page |41
11. SHARE CAPITAL
Authorized
The authorized share capital consists of an unlimited number of common voting shares without par value and an unlimited number of preferred shares.
Issued and Outstanding
Common shares ($000s except number of shares)
Balance, December 31, 2016
Common shares issued under equity financing (a)
Common shares issued under the arrangement agreement
Share issue costs
Balance, December 31, 2017 and December 31, 2018
Share Issuances
Number of Shares
45,349,192
4,078,708
63,940
—
49,491,840
Amount
419,672
10,319
179
(51)
430,119
(a) On February 28, 2017 the Company issued 4,078,708 common shares at a price of $2.53 per share through a non-brokered private placement.
SHARE-BASED COMPENSATION
Stock Options
The Company has a stock option plan in place whereby it may issue stock options to employees, consultants and directors of the Company. The aggregate
number of shares that may be acquired upon exercise of all options granted pursuant to the plans shall, at any date or time of determination, be equal to ten
percent (10%) of the number that is equal to (i) the number of the Company’s basic common shares then issued and outstanding; minus (ii) a number equal
to five (5) times the number of common shares that are issuable upon exercise of the then outstanding Performance Warrants, if any, minus (iii) a number
equal to fifty percent (50%) of the number of common shares that have previously been issued upon the exercise of Performance Warrants, if any.
At December 31, 2018, 3,082,880 (December 31, 2017 – 2,914,930) stock options were outstanding. The summary of stock option activity is presented below:
Balance, December 31, 2016
Granted
Exercised
Forfeited or expired
Balance, December 31, 2017
Granted
Forfeited
Expired
Balance, December 31, 2018
Exercisable, December 31, 2018
Number of stock
options
1,976,580
1,855,200
(232,071)
(684,779)
2,914,930
1,208,880
(492,410)
(548,520)
3,082,880
443,700
Weighted average
exercise price
$6.56
$2.26
$1.98
$6.61
$4.21
$1.14
$5.94
$3.43
$2.87
$10.44
The following table summarizes information about the stock options granted since inception:
Range of Exercise Price
Stock Options Outstanding
Stock Options Exercisable
Weighted
Weighted
$0.86 - $2.33
$9.00 - $16.00
Weighted
average
Weighted
average
Number
granted
2,750,380
332,500
3,082,880
average
exercise price
$1.74
$12.18
$2.87
remaining life
(years)
1.17
0.65
1.11
Number
exercisable
111,200
332,500
443,700
average
exercise price
$2.33
$13.15
$10.44
remaining life
(years)
0.03
0.65
0.49
During the year ended December 31, 2018 and the year ended December 31, 2017, the Company granted options which vest equally over three (3) years, and
upon vesting, expire 30 business days thereafter. The weighted average fair value of each option granted in 2018 of $0.30 (2017 – $0.64) was estimated on the
date of grant using the Black-Scholes pricing model with the following weighted average assumptions:
Page |42
Risk free interest rate
Expected life (years)
Estimated volatility of underlying common shares (%)
Estimated forfeiture rate
Expected dividend yield (%)
2018
2017
1.70% - 1.90%
1.08 - 3.08
63% - 65%
20%
0%
0.80% - 0.95%
1.08 - 3.08
65%
20%
0%
Petrus estimated the volatility of the underlying common shares by analyzing the Company's volatility as well as the volatility of peer group public companies
with similar corporate structure, oil and gas assets and size.
Deferred Share Unit ("DSU") Plan
The Company has a deferred share unit plan in place whereby it may issue deferred share units to directors of the Company. The aggregate number of shares
that may be issued from treasury of Petrus pursuant to the plan shall not exceed: (i) five percent (5%) of the number of issued and outstanding common shares
of the Company (on a non-diluted basis) at the date of issue; and (ii) ten percent (10%) of the number of issued and outstanding common shares of the Company
(on a non-diluted basis) at the date of issue, less the aggregate number of common shares of the Company reserved for issuance under any other share
compensation plan.
Each DSU entitles the participants to receive, at the Company's discretion, either shares of the Company or cash equal to the trading price of the equivalent
number of shares of the Company. All DSUs granted vest and become payable upon retirement of the director.
The compensation expense was calculated using the fair value method based on the weighted average trading price of the Company's shares for the five trading
days ending on the reporting period date. At December 31, 2018, 382,796 (December 31, 2017 – 130,038) Deferred Share Units were issued and outstanding.
The following table summarizes the change in accrued compensation liability related to DSUs:
$000s
Balance, December 31, 2016
Change in accrued compensation liability
Balance, December 31, 2017
Change in accrued compensation liability
Balance, December 31, 2018
The following table summarizes the Company’s share-based compensation costs:
$000s
Expensed
Capitalized to exploration and evaluation assets
Capitalized to property, plant and equipment
Total share-based compensation
12. LOSS PER SHARE
—
244
244
(45)
199
Year ended
December 31, 2018
Year ended
December 31, 2017
576
70
212
858
503
55
164
722
Loss per share amounts are calculated by dividing the net loss for the period attributable to the common shareholders of the Company by the weighted average
number of common shares outstanding during the period.
Net loss for the year ($000s)
Weighted average number of common shares – basic (000s)
Weighted average number of common shares – diluted (000s)
Net loss per common share – basic
Net loss per common share – diluted
Year ended
December 31, 2018
Year ended
December 31, 2017
(3,284)
49,492
49,492
($0.07)
($0.07)
(111,261)
48,825
48,825
($2.28)
($2.28)
In computing diluted loss per share for the year ended December 31, 2018, 3,082,880 (December 31, 2017 – 2,914,930) outstanding stock options and 296,104
DSUs were considered.
Page |43
13. OPERATING EXPENSES
The Company’s gross operating expenses for the year ended December 31, 2018 were $16.7 million (December 31, 2017 – $20.0 million). For the year ended
December 31, 2018, this includes $3.6 million of processing, gathering and compression charges (December 31, 2017 – $6.3 million).
The Company generated processing income recoveries of $1.0 million for the year ended December 31, 2018 (December 31, 2017 – $1.1 million), which reduced
the Company’s gross operating expenses to $15.7 million for the year ended December 31, 2018 (December 31, 2017 – $19 million).
14. GENERAL AND ADMINISTRATIVE EXPENSES
The Company’s general and administrative expenses consisted of the following expenditures:
$000s
Personnel, consultants and directors
Office costs
Regulatory and public company expenses
Gross general and administrative expense
Capitalized general and administrative expense and overhead recoveries
General and administrative expense
15. FINANCIAL INSTRUMENTS
Risks associated with financial instruments
2018
4,610
2,588
1,031
8,229
(3,045)
5,184
2017
4,803
2,929
1,055
8,787
(5,535)
3,252
Credit risk
The Company’s accounts receivable are with customers and joint venture partners in the petroleum and natural gas business and are subject to normal
credit risk. Concentration of credit risk is mitigated by marketing the majority of the Company’s production to reputable and financially sound purchasers
under normal industry sale and payment terms. As is common in the petroleum and natural gas industry in western Canada, Petrus’ receivables relating
to the sale of petroleum and natural gas are received on or about the 25th day of the following month. Of the $12.7 million of accounts receivable outstanding
at December 31, 2018 (December 31, 2017 – $11.6 million), $7.1 million is owed from 4 parties (December 31, 2017 – $8.7 million from 4 parties), and the
balances were received subsequent to year end. The Company considers accounts receivable outstanding past 120 days to be 'past due'. At December 31,
2018, the Company had an allowance for doubtful accounts of $0.2 million (December 31, 2017 – $0.1 million). As at December 31, 2018, 99% of Petrus’
accounts receivable were aged less than 120 days and 1% of Petrus' accounts receivable were aged greater than 120 days. The Company does not anticipate
any significant collection issues.
The Company’s risk management assets and cash are with chartered Canadian banks and the Company does not consider these assets to carry material
credit risk.
Liquidity risk
At December 31, 2018, the Company had a $110 million RCF (lender consent is required for total borrowings against the RCF exceeding $105 million, see
note 8), on which $97.0 million was drawn (December 31, 2017 – $97.6 million). While the Company is exposed to the risk of reductions to the borrowing
base of the RCF, the Company anticipates it will continue to have adequate liquidity to fund its financial liabilities through funds flow and available credit
capacity from its RCF. The next scheduled borrowing base redetermination date for the RCF is on or before May 31, 2019.
The following are the contractual maturities of financial liabilities as at December 31, 2018:
$000s
Accounts payable
Bank indebtedness and long term debt(1)
Total
(1)Excludes deferred finance fees.
Total
21,646
132,380
154,026
< 1 year
21,646
380
22,026
1-5 years
—
132,000
132,000
Page |44
Interest Rate Risk
Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The Company’s cash, bank indebtedness and
accounts receivable are not exposed to significant interest rate risk. The RCF and Term Loan are exposed to interest rate cash flow risk as the instruments
are priced on a floating interest rate subject to fluctuations in market interest rates. The remainder of Petrus’ financial assets and liabilities are not exposed
to interest rate risk. A 1% increase in the Canadian prime interest rate during the year ended December 31, 2018 would have increased net loss by
approximately $1.3 million which relates to interest expense on the average outstanding RCF and Term Loan during the period assuming that all other
variables remain constant (December 31, 2017 – increased net loss by $1.2 million). A 1% decrease in the Canadian prime interest rate during the period
would result in an opposite impact on net loss.
Commodity Price Risk
Commodity price risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in commodity prices. A significant change in
commodity prices can materially impact the Company’s borrowing base limit under its Revolving Credit Facility and may reduce the Company’s ability to
raise capital. Commodity prices for petroleum and natural gas are not only influenced by Canadian and United States demand, but also by world events
that dictate the levels of supply and demand.
The Company manages the risks associated with changes in commodity prices by entering into a variety of financial derivative contracts (see note 10). The
Company assesses the effects of movement in commodity prices on net loss. When assessing the potential impact of these commodity price changes, the
Company believes a $5/CDN WTI/bbl change in the price of oil and a $0.25/GJ change in the price of natural gas are reasonable measures.
As at December 31, 2018, it was estimated that a $0.25/GJ decrease in the price of natural gas would have increased net loss by $1.8 million (December 31,
2017 – $3.6 million). An opposite change in commodity prices would result in an opposite impact on net loss. As at December 31, 2018, it was estimated
that a $5.00/CDN WTI/bbl decrease in the price of oil would have increased net loss by $4.0 million (December 31, 2017 – $5.4 million). An opposite change
in commodity prices would result in an opposite impact on net loss.
16. CAPITAL MANAGEMENT
The Company’s general capital management policy is to maintain a sufficient capital base in order to manage its business to enable the Company to increase
the value of its assets and therefore its underlying share value. In the management of capital, the Company includes share capital and total net debt, which is
made up of debt and working capital (current assets less current liabilities). The Company manages its capital structure and makes adjustments in light of
economic conditions and the risk characteristics of the underlying assets. In order to maintain or adjust the capital structure, Petrus may issue new equity,
increase or decrease debt, adjust capital expenditures and acquire or dispose of assets.
17. FINANCE EXPENSES
The components of finance expenses are as follows:
$000s
Cash:
Interest
Foreign exchange
Total cash finance expenses
Non-cash:
Deferred financing costs
Accretion on decommissioning obligations (note 9)
Total non-cash finance expenses
Total finance expenses
2018
2017
8,272
1
8,273
637
887
1,524
9,797
6,992
2
6,994
406
989
1,395
8,389
Page |45
18. SUPPLEMENTAL CASH FLOW INFORMATION
The following table reconciles the changes in non-cash working capital as disclosed in the statements of cash flows:
$000s
Source (use) in non-cash working capital:
Deposits and prepaid expenses
Transaction costs on debt
Accounts receivable
Accounts payable and accrued liabilities
Operating activities
Financing activities
Investing activities
2018
133
(18)
(1,087)
(4,110)
(5,082)
(4,764)
298
(615)
2017
(319)
—
(61)
3,291
2,911
931
(847)
2,826
The following table reconciles the changes in liability resulting from financing activities:
$000s
Balance, December 31, 2017
Cash flows
Non-cash changes
Balance, December 31, 2018
Bank Indebtedness
Revolving Credit
Facility
Term Loan Total Liabilities from
Financing Activities
3,844
(3,464)
—
380
97,600
(600)
—
97,000
34,307
—
114
34,421
135,751
(4,064)
114
131,801
19. COMMITMENTS AND CONTINGENCIES
COMMITMENTS
The commitments for which the Company is responsible are as follows:
$000s
Corporate office lease
Firm service transportation
Total commitments
Total
775
19,739
20,515
< 1 year
715
1,374
2,089
1-5 years
60
12,870
12,930
> 5 years
—
5,495
5,495
CONTINGENCIES
In the normal course of Petrus’ operations, the Company may become involved in, named as a party to, or be the subject of, various legal proceedings. The
outcome of outstanding, pending or future proceedings cannot be predicted with certainty. Petrus does not anticipate that these claims will have a
material impact on its financial position.
20. RELATED PARTY TRANSACTIONS
The Company considers its directors and officers to be key management personnel. The following table outlines transactions with key management personnel:
$000s
Salaries, consulting fees, benefits and director fees, gross
Share based compensation, gross
2018
1,563
274
1,837
2017
1,690
482
2,172
On February 28, 2017, the Chairman of the Company acquired 1,585,000 common shares ("Common Shares") of Petrus Resources Ltd. at a price of $2.53 per
Common Share, pursuant to a non-brokered private placement of Common Shares (see note 11). The total consideration paid by the Chairman for the acquisition
of the 1,585,000 Common Shares was $4,010,050.
Page |46
21. REVENUE
The following table presents Petrus' oil and natural gas revenue disaggregated by product type:
$000s
Production Revenue
Oil and condensate sales
Natural gas sales
Natural gas liquids sales
Total oil and natural gas production revenue
Royalty revenue
Total oil and natural gas revenue
22. DEFERRED INCOME TAXES
$000s
Loss before taxes
Combined federal and provincial tax rate
Computed “expected” tax recovery
Increase/(decrease) in taxes resulting from:
Permanent items
Share based payments
Share issuance costs
True up and other
Unrecognized deferred income tax asset
Deferred tax expense (recovery)
Effective tax rate
The components of the Company’s deferred tax position at December 31, 2018 and 2017 are as follows:
$000s
Exploration and evaluation assets and property, plant and equipment
Asset retirement obligations
Share issuance costs
Non capital loss carry-forwards
Unrealized hedging loss
Deferred tax liability
2018
2017
35,684
23,453
21,186
80,323
393
80,716
2018
(3,284)
27.0%
(887)
7
156
(95)
(1,135)
1,954
—
—%
2018
(12,842)
—
278
15,138
(2,574)
—
39,633
38,156
12,685
90,474
95
90,569
2017
(111,261)
27.0%
(30,323)
5
136
(14)
(1,264)
31,460
—
—%
2017
(1,847)
—
546
1,847
(546)
—
The Company had non-capital losses of approximately $217.8 million (2017 – $160.9 million) which may be applied against future income for Canadian tax
purposes. These non-capital losses expire in 2027 and onwards.
Page |47
CORPORATE INFORMATION
OFFICERS
Neil Korchinski, P. Eng.
President and
Chief Executive Officer
Cheree Stephenson, CA, CPA
Vice President, Finance and
Chief Financial Officer
Marcus Schlegel, P. Eng.
Vice President, Engineering
Brett Booth, BA
Vice President, Land
Ross Keilly, BSc, MSc
Vice President, Exploration
DIRECTORS
Don T. Gray
Chairman
Scottsdale, Arizona
Neil Korchinski
Calgary, Alberta
Patrick Arnell
Calgary, Alberta
Donald Cormack
Calgary, Alberta
Stephen White
Calgary, Alberta
SOLICITOR
Burnet, Duckworth & Palmer LLP
Calgary, Alberta
AUDITOR
Ernst & Young LLP
Chartered Professional Accountants
Calgary, Alberta
INDEPENDENT RESERVE EVALUATORS
Sproule and Associates
Calgary, Alberta
BANKERS
TD Securities
Calgary, Alberta
Macquarie Bank Limited
Houston, Texas
TRANSFER AGENT
Computershare Trust Company
Calgary, Alberta
HEAD OFFICE
2400, 240 – 4th Avenue S.W.
Calgary, Alberta T2P 5H4
Phone: 403-984-9014
Fax: 403-984-2717
WEBSITE
www.petrusresources.com
Page |48