ANNUAL REPORT
December 31, 2019
2019 HIGHLIGHTS
Petrus Resources Ltd. (“Petrus” or the “Company”) (TSX: PRQ) is pleased to report financial and operating results as at and for the three and
twelve months ended December 31, 2019 and to provide 2019 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 are available on
SEDAR (the System for Electronic Document Analysis and Retrieval) at www.sedar.com.
In 2019, the Company's primary objectives were to generate funds flow in excess of capital expenditures to repay debt and to maximize the
profitability of its production by increasing its light oil weighting. Petrus generated funds flow of $33.6 million in 2019 and invested approximately
half ($18.1 million) to drill 10 gross (3.1 net) Cardium light oil wells in Ferrier. The Company exceeded its debt repayment target for the year
and used $15.5 million of its funds flow to reduce net debt(1). Despite average annual production being 8% lower year over year, funds flow
was higher in 2019 due to increased light oil weighting, lower costs and improved commodity pricing.
• Debt repayment - Reduction of debt is the Company's first and foremost priority. Since December 31, 2015 Petrus has repaid $103
million (45%) of net debt(1). This includes a $55 million reduction of the Company's second lien term loan ("Term Loan") which was
$90 million in 2014 and currently has $35 million outstanding. The Company's revolving credit facility ("RCF") and Term Loan are due
in 2020 and therefore have been reclassified to current liabilities in the December 31, 2019 consolidated financial statements. The
RCF maturity date is May 31, 2020 which was set prior to the Term Loan maturity of October 8, 2020 due to the inter-creditor
relationship between the RCF and the Term Loan. The Company requires an extension of its Term Loan before the syndicate of lenders
will contemplate an extension to the RCF. Management is currently in discussion with the Term Loan lender and continues to focus
on its disciplined debt reduction strategy.
• Stronger natural gas pricing - The average benchmark natural gas price in Canada (AECO 5A monthly index) was $2.35/GJ in the
fourth quarter, a significant increase from the third quarter 2019 average price of $0.87/GJ. In January 2020 the AECO 5A monthly
index was $2.18/GJ. Petrus anticipates the impacts of TC Energy Corporation's previously announced Temporary Service Protocol,
continued expansion of the NGTL system in 2020 and 2021 and current Alberta natural gas storage levels will all continue to support
Canadian natural gas prices(2).
• Higher funds flow per share - Fourth quarter 2019 production of 8,292 boe/d was 5% higher than the prior year and quarterly
funds flow per share was $0.19 in 2019, significantly higher (90%) than the $0.10 generated in the prior year.
• Free funds flow - In 2019 Petrus generated funds flow of $33.6 million ($0.68 per share), invested $18.1 million of capital to maintain
production and exceeded its debt reduction target of $1 to $2 million per quarter; net debt(1) was reduced by $15.5 million. During
the fourth quarter of 2019, Petrus generated funds flow of $9.3 million, more than double the funds flow generated in the third
quarter.
• Increased light oil weighting - Fourth quarter average production included 1,834 bbl/d of light oil, which was a 47% increase from
the third quarter. This was attributable to the new wells brought on production during the fourth quarter.
• Increased light oil reserve volumes - In 2019, the Company realized Finding Development and Acquisition (“FD&A”) costs of $13.31
per boe for PDP reserves. These finding costs were consistent with the best in the Company’s history. In 2019, Petrus’ development
program generated PDP reserve volume additions of 1.3 mmboe which were comprised of 45% light oil. The Company produced 3.0
mmboe during 2019 and ended the year with 11.7 mmboe of PDP reserve volume (34% oil and liquids).
• Company best operating costs - Total annual operating costs were 11% lower than 2018 at $4.25 per boe in 2019, which is the
lowest in the Company's history (a 68% decrease since 2012). This marks the fourth 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.
• Non-core asset disposition - In December 2019, Petrus entered into an agreement for the sale of its oil and natural gas interests
in the Foothills area of Alberta to an arm's length private company for total consideration of $1.8 million (the "Disposition"). The
Disposition is expected to close in the first quarter of 2020, subject to regulatory approvals. The Company expects it will reduce Petrus’
undiscounted, uninflated decommissioning obligation by approximately $7.5 million or 18%. The cash proceeds from the Disposition
will be used to reduce the borrowings under the Company's credit facility(2).
Page |2
2020 Outlook
Petrus’ Board of Directors has approved a first quarter 2020 capital budget of $9.0 million to drill 2 (2.0 net) Cardium wells in the Ferrier area.
First quarter funds flow combined with proceeds from the previously announced non-core asset disposition are expected to total $9.5 million
which will permit excess funds to be directed toward debt repayment(2). Petrus is committed to maintaining its financial flexibility and the
Company will determine subsequent quarter capital spending as the year progresses. For the coming year there is significant optionality in
the number, the commodity composition and the location of drilling opportunities. Management anticipates that the 2020 capital plan will
be funded by funds flow, and will continue to systematically reduce debt each quarter by approximately $1 to $2 million. The objectives of
the 2020 capital plan are to reduce debt, maintain or grow production, grow funds flow per share and increase the Company’s liquids weighting.
Petrus continues its efforts to divest additional non-core assets to improve the balance sheet and also continues its discussions with its lenders
in order to extend the upcoming 2020 debt maturity dates.
(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 - Presentation" in the Management's Discussion & Analysis attached hereto.
Page |3
PRESIDENT’S MESSAGE
The energy industry had another very challenging year in 2019. At the beginning of the year, we set out with the primary
goal of strengthening our balance sheet, using excess funds flow to reduce debt by approximately $1 - $2 million per quarter,
while targeting to maintain our annual funds flow of $33 million. In order to accomplish this systematic deleveraging, the
Petrus team embarked on a very disciplined capital program targeting maximum efficiency of capital deployment and
operating performance.
During the year we were able to exceed our goal, reducing net debt by $15.5 million with annual funds flow of $33.6 million.
Our 2019 capital program of $18.1 million was the lowest annual total in the Company’s history. The development plan
targeted exclusively Cardium oil locations in Ferrier. This drilling program surpassed 2018, becoming the most efficient in
the Company’s history in terms of rate of return and payout. We were able to add new production at a cost of approximately
$14,300/boed, which represents the average of the three previous years. At $13.31/boe, our PDP FD&A cost was one of
the lowest finding costs we have achieved. For the fourth year in a row we have reduced our annual operating costs which
in 2019 were $4.25/boe. And in addition to reducing net debt, the Company has also worked to reduce its abandonment
and reclamation obligations. With the completion of the Foothills sale our undiscounted, uninflated ARO will reduce by
$7.5 million (18%) to a total of approximately $34 million. This will put our ARO per quarterly boe of production in the top
third of our peers and less than half the average of the group.
In 2020, we will continue to improve our balance sheet by drilling Ferrier Cardium oil locations, increasing our liquids
weighting, monetizing non-core assets, reducing operating costs and continuing to deploy capital as efficiently as possible.
With pricing volatility, it is paramount that we remain disciplined and adaptable in our approach. We are committed to
reducing our debt on a systematic basis, targeting debt repayment of $1 to $2 million per quarter. By improving our balance
sheet and continuing to improve our project execution, Petrus will not only be able to withstand further pricing volatility
but also have the flexibility to increase drilling investment should pricing allow.
Neil Korchinski
President, Chief Executive Officer and Director
Page |3
RESERVES
Petrus’ 2019 year end reserves were evaluated by independent reserves evaluator, Sproule Associates Limited, 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, 2019 ("2019 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, 2019, which will
be available under the Company's profile on SEDAR (the System for Electronic Document Analysis and Retrieval) at www.sedar.com.
Petrus has a reserves committee, comprised of independent board members, that reviews the qualifications and appointment of the
independent reserves evaluator. 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 evaluator 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 2019 Sproule Report.
The following table provides a summary of the Company’s before tax reserves as evaluated by Sproule:
As at December 31, 2019
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)
46,105
18,202
56,397
120,703
59,232
62,672
1,248
5
1,260
2,513
1,671
2,477
NGL
(mbbl)
Total
(mboe)
NPV 0%(2)
($000s)
NPV 5%(2)
($000s)
NPV 10%(2)
($000s)
2,723
91
4,763
7,576
3,414
3,773
11,655
3,129
15,422
30,207
14,957
16,696
143,061
15,255
204,442
362,758
212,786
306,799
151,543
11,428
138,197
301,168
194,341
207,302
138,707
9,032
95,400
243,140
167,735
149,307
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 0%, 5% and 10%, respectively
and is presented before tax and based on Sproule's pricing assumptions.
(3)Total company interest reserve volumes 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).
669,557
183,376
508,470
392,446
46,902
11,350
4,990
In 2019, Petrus’ development program generated Proved Developed Producing ("PDP") reserve volume additions of 1.3 mmboe which were
comprised of 45% light oil. The Company produced 3.0 mmboe during 2019 and ended the year with 11.7 mmboe of PDP reserve volume (34%
oil and liquids).
Petrus ended 2019 with $147.7 million, $243.1 million and $392.4 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 2019 Sproule Report. In 2019, the Company realized
Finding and Development (“FD&A”)(1)(2) costs of $13.31/boe for PDP reserves.
Based on the 2019 Sproule Report, the Company’s PDP reserve value before-tax, discounted at 10% is $2.80 per share. On the same basis, the
P+P reserve value is $7.93 per share.
(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.
Page |4
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.
The following table provides a summary of the Company's FDC as set forth in the 2019 Sproule Report:
Future Development Cost ($000s)
2020
2021
2022
2023
Thereafter
Total FDC, Undiscounted
Total FDC, Discounted at 10%
Total Proved
Total Proved + Probable
41,019
72,106
50,186
5,782
4,934
174,027
149,383
54,452
135,558
57,561
15,147
4,934
267,652
229,770
PERFORMANCE RATIOS
The following table highlights annual performance ratios for the Company from 2015 to 2019:
Proved Producing
FD&A ($/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)
December 31, 2019
December 31, 2018
December 31, 2017
December 31, 2016
December 31, 2015
13.31
12.81
3.8
0.4
1.2
12.49
12.03
4.8
0.5
1.3
1.09
(6.83)
9.9
0.3
14.4
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
Future Development Cost ($000s)
174,027
194,757
182,086
201,556
223,409
Total Proved + Probable
FD&A ($/boe) (1)(2)
F&D ($/boe) (1)(2)
Reserve Life Index (yr) (1)
Reserve Replacement Ratio (1)
FD&A Recycle Ratio (1)
(7.32)
190.21
15.4
—
(2.1)
6.49
5.15
17.1
1.5
2.4
14.87
17.28
12.3
1.7
1.0
350.09
(8.06)
14.6
(0.1)
—
15.40
19.01
16.4
3.7
1.0
Future Development Cost ($000s)
(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.
267,652
325,325
290,876
269,144
283,030
Page |5
NET ASSET VALUE
The following table shows the Company's Net Asset Value ("NAV"), calculated using Sproule's December 31, 2019 price forecast:
Total Proved
Proved + Probable
243,140
36,116
(123,744)
155,512
392,446
36,116
(123,744)
304,818
$6.16
As at December 31, 2019 ($000s except per share)
Present Value Reserves, before tax (discounted at 10%) (1)
Undeveloped Land Value (2)
Net Debt (3)
Net Asset Value
Proved Developed
Producing
138,707
36,116
(123,744)
51,079
Estimated Net Asset Value per Share
(1)Based on the 2019 Sproule Report, using the forecast future prices and costs.
(2)Based on the exploration and evaluation assets as per the Company's December 31, 2019 audited consolidated financial statements.
(3)See "Non-GAAP Financial Measures" in the Management's Discussion & Analysis attached hereto.
$1.03
$3.14
Page |6
MANAGEMENT’S DISCUSSION & ANALYSIS
The following is Management’s Discussion and Analysis ("MD&A") of the financial and operating results of Petrus Resources Ltd. ("Petrus" or
the "Company") as at and for the three and twelve months ended December 31, 2019. This MD&A is dated February 18, 2020 and should be
read in conjunction with the Company's audited consolidated financial statements for the years ended December 31, 2019 and 2018. The
Company’s audited consolidated financial statements are prepared in accordance with Canadian generally accepted accounting principles
("GAAP") which require publicly accountable enterprises to prepare their financial statements using International Financial Reporting Standards
("IFRS"). Readers are directed to the "Advisories" section at the end of this MD&A regarding forward-looking statements and boe presentation
and to the section "Non-GAAP Financial Measures" herein.
The principal undertaking of Petrus is the investment in energy assets. The operations of the Company consist of the acquisition, development,
exploration and exploitation of these assets. The Company’s head office is located at 2400, 240 - 4th Avenue SW, Calgary, Alberta, Canada.
Additional information on Petrus, including the most recently filed Annual Information Form ("AIF"), are available under the Company's profile
on SEDAR (the System for Electronic Document Analysis and Retrieval) at www.sedar.com.
Page |7
SELECTED FINANCIAL INFORMATION
OPERATIONS
Average Production
Natural gas (mcf/d)
Oil (bbl/d)
NGLs (bbl/d)
Total (boe/d)
Total (boe)
Light oil weighting
Realized Prices
Natural gas ($/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 & corporate netback(1)(2)
($/boe)
Twelve months
ended
Dec. 31, 2019
Twelve months
ended
Dec. 31, 2018
Three months
ended
Dec. 31, 2019
Three months
ended
Sept. 30, 2019
Three months
ended
Jun. 30, 2019
Three months
ended
Mar. 31, 2019
32,032
1,616
1,351
8,306
37,101
1,402
1,433
9,019
3,031,659
3,292,828
32,641
1,834
1,018
8,292
762,874
30,998
1,247
1,372
7,785
716,220
32,350
1,679
1,576
8,647
786,819
32,145
1,704
1,444
8,505
765,488
19%
16%
22%
16%
19%
20%
1.89
64.11
22.13
23.35
0.20
(2.35)
21.20
(4.25)
(1.26)
15.69
(0.44)
0.03
(1.20)
(2.72)
(0.28)
11.08
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
2.65
65.16
20.62
27.39
0.13
(2.91)
24.61
(4.47)
(1.30)
18.84
(1.86)
—
(1.91)
(2.54)
(0.41)
12.12
1.12
65.64
11.49
16.99
0.48
(1.65)
15.82
(4.44)
(1.25)
10.13
0.50
0.03
(1.08)
(3.11)
(0.29)
6.18
1.30
70.96
19.91
22.29
0.15
(1.72)
20.72
(4.33)
(1.22)
15.17
(1.02)
0.10
(0.67)
(2.70)
(0.24)
10.64
2.44
55.10
36.02
26.36
0.06
(3.08)
23.34
(3.76)
(1.27)
18.31
0.67
—
(1.15)
(2.54)
(0.18)
15.11
FINANCIAL (000s except $ per share)
Twelve months
ended
Dec. 31, 2019
Twelve months
ended
Dec. 31, 2018
Three months
ended
Dec. 31, 2019
Three months
ended
Sept. 30, 2019
Three months
ended
Jun. 30, 2019
Three months
ended
Mar. 31, 2019
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 dispositions
Weighted average shares outstanding
Basic
Fully diluted
As at year end
Common shares outstanding
Basic
Fully diluted
Total assets
Non-current liabilities
Net debt(1)
71,398
(42,176)
(0.85)
(0.85)
33,625
0.68
0.68
18,073
651
49,472
49,472
49,469
49,469
289,225
42,346
123,744
80,716
(3,284)
(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
20,998
(3,332)
12,517
(29,569)
(0.06)
(0.06)
9,260
0.19
0.19
4,351
—
(0.60)
(0.60)
4,427
0.09
0.09
2,734
651
49,469
49,469
49,469
49,469
49,469
49,469
289,225
42,346
123,744
49,469
49,469
296,367
82,650
128,553
17,652
2,863
0.06
0.06
8,366
0.17
0.17
2,505
—
49,469
49,469
49,469
49,469
328,912
81,249
130,619
20,231
(12,138)
(0.25)
(0.25)
11,573
0.23
0.23
8,483
—
49,483
49,483
49,469
49,469
336,974
176,093
136,382
(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 comparable additional GAAP measure. Petrus analyzes these measures on an absolute value and per unit basis.
Page |8
OPERATIONS UPDATE
Fourth quarter average production by area was as follows:
For the three months ended December 31, 2019
Natural gas (mcf/d)
Oil (bbl/d)
NGLs (bbl/d)
Total (boe/d)
Ferrier
25,149
1,357
852
6,401
Foothills
Central Alberta
1,745
135
8
433
5,747
342
158
1,458
Total
32,641
1,834
1,018
8,292
Fourth quarter average production was 8,292 boe/d in 2019 compared to 7,785 boe/d in the third quarter of 2019. During the second half of
2019 the Company drilled 7 gross (1.6 net) Cardium light oil wells. Average production from the 1.6 net wells over the fourth quarter, net to
Petrus, was approximately 560 bbl/d of oil and approximately 1,600 mcf/d of natural gas. The Company's development plan is strategically
balanced between increasing its Cardium light oil weighting in the Ferrier area and continuing to improve its balance sheet. In 2019, Petrus
drilled 10 gross (3.1 net) Cardium light oil wells, increased its light oil weighting 24% from the beginning of 2018 and reduced net debt(1) $15.5
million. Since December 31, 2017 Petrus has repaid $24.3 million (16%) of net debt.
The average benchmark natural gas price in Canada (AECO 5A monthly index) was $2.35/GJ in the fourth quarter, a significant increase from
the third quarter 2019 average price of $0.87/GJ. Petrus anticipates the impacts of TC Energy Corporation's previously announced Temporary
Service Protocol, continued expansion of the NGTL system in 2020 and 2021 and current Alberta natural gas storage levels will all continue to
support Canadian natural gas prices(2).
Petrus’ Board of Directors has approved a first quarter 2020 capital budget of $9.0 million to drill 2 (2.0 net) Cardium light oil wells in the Ferrier
area. First quarter funds flow combined with proceeds from the previously announced non-core asset disposition are expected to total $9.5
million which will provide excess funds to be directed toward debt repayment. Management anticipates that the 2020 capital plan will be
funded by funds flow, and will continue to systematically reduce debt each quarter by approximately $1 to $2 million. The objectives of the
2020 capital plan are to reduce debt, maintain or grow production, grow funds flow per share and increase the Company’s liquids weighting
(2).
Petrus believes it is unique in the junior E&P company space, as few gas-weighted companies are able to repay debt and grow production and
funds flow all within funds from operations. Over the past four years, Petrus has dramatically strengthened its business in order to improve its
sustainability as well as mitigate commodity price risk. Operating costs have been reduced by 68% since 2012 and management believes Petrus’
total cash costs of $9.43/boe are consistently one of the lowest amongst its peers. The Company intends to continue its disciplined focus on
balance sheet improvement and capital deployment in 2020(2).
CREDIT FACILITY UPDATE
In November 2019, Petrus completed its semi-annual revolving credit facility ("RCF") review where its $100 million facility was reconfirmed.
On December 31, 2019 Petrus reduced its borrowings under the RCF by $2 million and expects to make another $2 million repayment on March
31, 2020. The Company's RCF maturity date is May 31, 2020 which was set prior to the Company's term loan maturity date of October 8, 2020
("Term Loan"), due to the inter-creditor relationship between the RCF and the Term Loan. The Company requires an extension of its Term Loan
before the syndicate of lenders will contemplate an extension to the RCF. The borrowings under the RCF and Term Loan are classified as current
liabilities in the December 31, 2019 consolidated financial statements which has no impact on the debt covenants and the Company remains,
and expects to continue to be, in compliance with each of its covenants. Management is actively engaged in discussions with its lenders in
order to extend the upcoming 2020 maturity dates. The Company continues its efforts to divest certain non-core assets to improve its balance
sheet.
NON-CORE ASSET DISPOSITION
In December 2019, Petrus entered into an agreement for the sale of its oil and natural gas interests in the Foothills area of Alberta to an arm's
length private company for total consideration of $1.8 million, subject to regulatory approvals and customary closing conditions and adjustments
(the “Disposition”). The Disposition has an effective date of November 1, 2019 and is expected to close in the first quarter of 2020. In the
fourth quarter of 2019, production in the Company’s Foothills area averaged approximately 433 boe/d (67% natural gas), which comprised 5%
of Petrus’ total production. The Foothills assets include facility interests and 35,127 net acres of undeveloped land. The Disposition is expected
to reduce the Company's indebtedness, operating expenses and future abandonment liabilities. It is expected to reduce Petrus’ undiscounted,
uninflated decommissioning obligation by $7.5 million or 18%. The cash proceeds from the Disposition will be used to reduce the borrowings
under the Company's RCF.
(1)Refer to "Non-GAAP Financial Measures."
(2)Refer to "Advisories - Forward-Looking Statements."
Page |9
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
($/boe)
Average benchmark prices
Natural gas
AECO 5A (C$/GJ)
AECO 7A (C$/GJ)
Crude oil
Mixed Sweet Blend Edm
(C$/bbl)
Natural gas liquids
Propane Conway (US$/bbl)
Butane Edmonton (C$/bbl)
Foreign exchange
US$/C$
Twelve months
ended
Dec. 31, 2019
Twelve months
ended
Dec. 31, 2018
Three months
ended
Dec. 31, 2019
Three months
ended
Sept. 30, 2019
Three months
ended
Jun. 30, 2019
Three months
ended
Mar. 31, 2019
32,032
1,616
1,351
8,306
37,101
1,402
1,433
9,019
3,031,659
3,292,828
22,052
37,815
10,917
614
71,398
1.89
64.11
22.13
23.35
(0.44)
22.91
23,453
35,684
21,186
393
80,716
1.73
69.74
40.50
24.40
(0.90)
23.50
32,641
1,834
1,018
8,292
762,874
7,970
10,995
1,931
102
20,998
2.65
65.16
20.62
27.39
(1.86)
25.53
30,998
1,247
1,372
7,785
716,220
3,192
7,529
1,450
346
12,517
1.12
65.64
11.49
16.99
0.50
17.49
32,350
1,679
1,576
8,647
786,819
3,839
10,841
2,855
117
17,652
1.30
70.96
19.91
22.29
(1.02)
21.27
32,145
1,704
1,444
8,505
765,488
7,051
8,450
4,681
49
20,231
2.44
55.10
36.02
26.36
0.67
27.03
Twelve months
ended
Dec. 31, 2019
Twelve months
ended
Dec. 31, 2018
Three months
ended
Dec. 31, 2019
Three months
ended
Sept. 30, 2019
Three months
ended
Jun. 30, 2019
Three months
ended
Mar. 31, 2019
1.67
1.54
69.03
20.34
21.70
0.75
1.42
1.45
69.13
30.71
35.07
0.77
2.35
2.21
66.81
19.78
36.96
0.76
0.87
0.99
69.21
15.56
24.78
0.76
0.98
1.11
72.66
20.60
24.43
0.75
2.48
1.84
67.46
24.40
5.91
0.75
Page |10
FUNDS FLOW AND NET INCOME (LOSS)
Petrus generated funds flow of $9.3 million in the fourth quarter of 2019 compared to $5.0 million in 2018. The 68% increase is due to higher
commodity prices in the fourth quarter of 2019. In the fourth quarter Petrus' total realized price was $27.39/boe compared to $21.91/boe in
the prior year.
For the year ended December 31, 2019, Petrus generated funds flow of $33.6 million compared to $33.2 million in the prior year. The 1%
decrease is due to lower production and lower commodity prices during the 12 month period.
Petrus reported a net loss of $3.2 million in the fourth quarter of 2019, compared to net income of $21.1 million in the fourth quarter of 2018.
The net income in the fourth quarter of 2018 compared to the net loss in the current year is primarily due to the accounting for unrealized
hedging on financial derivatives. During the fourth quarter of 2019, the Company recognized an unrealized loss of $3.7 million whereas during
the fourth quarter of 2018 a $25.4 million unrealized gain was recorded, which had a material impact on net income in the fourth quarter of
2018. The differences are due to changes in commodity prices at December 31 of the respective years.
On a twelve month basis, the Company generated a net loss of $42.2 million in 2019 compared to a net loss of $3.3 million in 2018. The increase
is primarily due to the $24.7 million impairment expense recorded during the third quarter of 2019 on the Company's non-core Foothills and
Central Alberta assets as well as the unrealized hedging loss of $11.3 million realized in 2019 (unrealized hedging gain of $7.5 million in 2018).
($000s except per share)
Three months ended
December 31, 2019
Three months ended
December 31, 2018
Twelve months ended
December 31, 2019
Twelve months ended
December 31, 2018
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
9,260
0.19
0.19
(3,176)
(0.06)
(0.06)
49,469
49,469
49,469
49,469
5,030
0.10
0.10
21,063
0.43
0.43
49,492
49,492
49,492
49,492
33,625
0.68
0.68
(42,176)
(0.85)
(0.85)
49,469
49,469
49,472
49,472
33,184
0.67
0.67
(3,284)
(0.07)
(0.07)
49,492
49,492
49,492
49,492
OIL AND NATURAL GAS REVENUE
Fourth quarter average production in 2019 was 8,292 boe/d (22% light oil), 5% higher than 2018 (7,934 boe/d; 17% light oil). Fourth quarter
oil and natural gas revenue in 2019 was $21.0 million compared to $16.1 million in 2018. The 30% increase is due to higher commodity prices
in addition to 5% higher production.
Annual average production in 2019 was 8,306 boe/d (19% light oil), 8% lower than 2018 (9,019 boe/d; 16% light oil). Total oil and natural gas
revenue decreased from $80.7 million for the year ended December 31, 2018 to $71.4 million in 2019 due to 8% lower production.
The following table provides a breakdown of composition of the Company's production volume by product:
Production Volume by Product (%)
Three months ended
December 31, 2019
Three months ended
December 31, 2018
Twelve months ended
December 31, 2019
Twelve months ended
December 31, 2018
Natural gas
Crude oil and condensate
Natural gas liquids
Total commodity sales from production
66%
22%
12%
100%
64%
17%
19%
100%
64%
20%
16%
100%
68%
16%
16%
100%
Page |11
The following table presents oil and natural gas revenue by product and the change from the prior comparative periods:
Oil and Natural Gas Revenue ($000s)
Three months ended
December 31, 2019
Three months ended
December 31, 2018
% Change
Twelve months ended
December 31, 2019
Twelve months ended
December 31, 2018
% Change
Natural gas
Crude oil and condensate
Natural gas liquids
Royalty income
Total oil and natural gas revenue
7,970
10,995
1,931
102
20,998
5,473
6,522
3,993
76
16,064
46 %
69 %
(52)%
34 %
31 %
22,052
37,815
10,917
614
71,398
23,453
35,684
21,186
393
80,716
(6)%
6 %
(48)%
56 %
(12)%
The following table provides the average benchmark the Company's average realized commodity prices:
Three months ended
December 31, 2019
Three months ended
December 31, 2018
% Change
Twelve months ended
December 31, 2019
Twelve months ended
December 31, 2018
% Change
Average benchmark prices
Natural gas
AECO 5A (C$/GJ)
AECO 7A (C$/GJ)
Crude oil
Mixed Sweet Blend Edm (C$/bbl)
Natural gas liquids
Propane Conway (US$/bbl)
Butane Edmonton (C$/bbl)
Average realized prices
Natural gas ($/mcf)
Oil ($/bbl)
NGLs ($/bbl)
Total average realized price
2.35
2.21
66.81
19.78
36.96
2.65
65.16
20.62
27.39
1.47
1.80
60 %
23 %
48.12
39 %
29.82
18.06
1.95
52.26
29.01
21.91
(34)%
105 %
36 %
25 %
(29)%
25 %
1.67
1.54
69.03
20.34
21.70
1.89
64.11
22.13
23.35
1.42
1.45
18 %
6 %
69.13
— %
30.71
35.07
1.73
69.74
40.50
24.40
(34)%
(38)%
9 %
(8)%
(45)%
(4)%
Natural gas
Natural gas revenue for the year ended December 31, 2019 was $22.1 million which accounted for 31% of oil and natural gas revenue, compared
to revenue of $23.5 million which accounted for 29% in 2018. The decrease is due to 14% lower natural gas production.
Fourth quarter 2019 average realized natural gas price was $2.65/mcf, compared to $1.95/mcf in 2018 (36% increase). Fourth quarter 2019
natural gas revenue was $8.0 million which accounted for 38% of oil and natural gas revenue, compared to revenue of $5.5 million accounting
for 34% in 2018. Fourth quarter natural gas revenue increased from 2018 due to higher natural gas production and 60% higher natural gas
pricing.
Crude oil and condensate
Oil and condensate revenue for the fourth quarter of 2019 was $11.0 million accounted for approximately 53% of oil and natural gas revenue,
compared to revenue of $6.5 million, accounting for 41% in 2018.
The average realized price of Petrus’ light oil and condensate was $65.16/bbl for the fourth quarter of 2019 compared to $52.26/bbl for the
prior year. The increase of 25% is attributable to the increase in commodity price.
Oil and condensate revenue for the year ended December 31, 2019 was $37.8 million, which accounted for 53% of oil and natural gas revenue,
compared to revenue of $35.7 million, which accounted for 44% in 2018.
The average realized price of Petrus’ light oil and condensate was $64.11/bbl for 2019 compared to $69.74/bbl for the prior year. The decrease
of 8% is attributable to pricing differentials.
Natural gas liquids (NGLs)
The Company’s NGL production mix consists of ethane, propane, butane and pentane. The pricing received for NGL production is based on
annual contracts effective the first of April each year. The contract prices are based on the product mix, the fractionation process required
Page |12
and the demand for fractionation facilities. In the fourth quarter of 2019, the Company's realized NGL price averaged $20.62/bbl, compared
to $29.01/bbl in the prior year. The 29% decrease is attributed to lower contract prices for the NGL byproducts. Fourth quarter market pricing
for propane at Conway decreased 34% from the prior year. Petrus' butane production is priced as a function of WTI (oil) which also decreased
in the fourth quarter compared to the prior year. In 2019, the Company's realized NGL price averaged $22.13/bbl compared to $40.50/bbl in
2018. Similar to the fourth quarter, the 45% decrease in realized pricing is attributed to lower market pricing for propane at Conway and WTI
(oil).
Petrus' ownership and control of critical processing facilities enables the Company to respond and continually optimize its production revenue
streams. To improve operating netback, during the third quarter of 2019, Petrus ceased sending certain natural gas for additional third party
deepcut processing to extract additional NGLs. This resulted in lower NGL production volume, however, the heating value of natural gas sales
increased and processing fees decreased. Petrus continues to monitor NGL market pricing and is able to modify its operations accordingly.
Fourth quarter 2019 NGL revenue was $1.9 million and accounted for 9% of oil and natural gas revenue, compared to revenue of $4.0 million
accounting for 25% in 2018.
NGL revenue for the year ended December 31, 2019 was $10.9 million and accounted for 15% of oil and natural gas revenue, compared to
revenue of $21.2 million, accounting for 26% in 2018.
ROYALTY EXPENSE
Royalties are paid to the Government of Alberta and to gross overriding royalty owners. The following table shows the Company’s royalty
expense (net of royalty allowances and incentives) for the periods shown:
Royalty Expense ($000s)
Crown
Percent of production revenue
Gross overriding
Total
Three months ended
December 31, 2019
Three months ended
December 31, 2018
Twelve months ended
December 31, 2019
Twelve months ended
December 31, 2018
1,232
6%
986
2,218
1,086
7%
1,350
2,436
3,298
5%
3,816
7,114
4,279
5%
7,359
11,638
Fourth quarter royalty expense decreased from $2.4 million in 2018 to $2.2 million in 2019 primarily due to lower NGL revenue and favorable
royalty rates on the new wells that came on production. For the year, total royalty expense decreased from $11.6 million in 2018 to $7.1 million
in 2019. The decrease is due to lower production and favorable royalty allowances.
Fourth quarter gross overriding royalties decreased from $1.4 million in 2018 to $1.0 million in 2019, due to lower light oil and NGL prices.
Gross overriding royalties for the year decreased from $7.4 million in 2018 to $3.8 million in 2019, due to the decrease in production and lower
NGL prices.
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, 2019
Three months ended
December 31, 2018
Twelve months ended
December 31, 2019
Twelve months ended
December 31, 2018
Realized hedging loss
Unrealized hedging gain (loss)
Net gain (loss) on derivatives
(1,417)
(3,668)
(5,085)
(573)
25,370
24,797
(1,344)
(11,273)
(12,617)
(2,961)
7,510
4,549
Page |13
In the fourth quarter, the Company recognized a realized hedging loss of $1.4 million in 2019, compared to a $0.6 million loss in 2018. The
realized losses are due to higher gas commodity prices (relative to the respective contracts outstanding). The realized loss in the fourth quarter
of 2019 decreased the Company’s total realized price by $1.86/boe, compared to $0.79/boe in 2018.
For the year, the Company recognized a realized hedging loss of $1.3 million in 2019, compared to the $3.0 million loss realized in 2018. The
realized losses are due to higher commodity prices (relative to the respective contracts outstanding). The realized losses decreased Petrus'
total realized price by $0.44 and $0.90 in 2019 and 2018, respectively.
The fourth quarter unrealized hedging loss of $3.7 million represents the change in the unrealized net risk management position during the
quarter. The unrealized hedging loss of $11.3 million for the year ended December 31, 2019 represents the change in the unrealized risk
management net asset position during 2019. These changes are a result of both the realization of hedging gains/losses during the year, changes
related to contracts entered into during the year as well as changes to commodity prices.
The Company’s risk management contracts provide protection from significant changes in crude oil and natural gas commodity prices for 2019,
2020 and 2021. The Company endeavors to hedge approximately half of its forecast production for the following year, and approximately 30%
of its forecast production for the subsequent year. The Company's hedging strategy is intended to provide stability and sustainability to the
Company's economic returns, funds flow and capital development plan. A summary of Petrus’ risk management contracts is included in note
11 of the Company’s consolidated financial statements as at and for the year ended December 31, 2019. The table below summarizes Petrus’
average crude oil and natural gas hedged volumes. The average volume of oil hedged for 2020 (1,075 bbl/d) represents 59% of fourth quarter
2019 average oil production. The 12,333 GJ/day average natural gas hedged for 2020 represents 36% of fourth quarter 2019 average natural
gas production.
The following table summarizes the average and minimum and maximum cap and floor prices for the 2019 to 2021 oil and natural gas contracts
outstanding as at the date of this MD&A:
Oil hedged (bbl/d)
Avg. WTI cap price ($C/bbl)
Avg. WTI floor price ($C/bbl)
Natural gas hedged (GJ/d)
Avg. AECO 7A cap price ($C/GJ)
Q1
Q2
2020
Q3
Q4
Avg.(1)
Q1
Q2
2021
Q3
Q4
Avg.(1)
1,450
1,150
950
750
1,075
500
300
300
300
350
73.23
76.33
76.71
75.12
75.16
72.83
74.02
72.80
72.80
73.07
73.23
76.33
76.71
75.12
75.16
72.83
74.02
72.80
72.80
73.07
15,500 12,500 12,500
8,833 12,333
7,000
4,000
4,000
1,333
4,083
1.76
1.52
1.52
1.52
1.59
1.59
1.61
1.61
1.63
1.63
1.60
1.60
1.60
1.60
1.60
1.60
1.61
1.61
1.52
Avg. AECO 7A floor price ($C/GJ)
(1)The volumes and prices reported are the weighted average volumes and prices for the period.
1.76
OPERATING EXPENSE
The following table shows the Company’s operating expense for the reporting periods shown:
Operating Expense ($000s)
Three months ended
December 31, 2019
Three months ended
December 31, 2018
Twelve months ended
December 31, 2019
Twelve months ended
December 31, 2018
Fixed and variable operating expense
Processing, gathering and compression charges
Total gross operating expense
Overhead recoveries
Total net operating expense
Operating expense, net ($/boe)
2,655
980
3,635
(228)
3,407
4.47
2,961
1,124
4,085
(234)
3,851
5.28
10,668
3,167
13,835
(962)
12,873
4.25
13,084
3,602
16,686
(1,034)
15,652
4.75
Fourth quarter net operating expense totaled $3.4 million in 2019, a 12% decrease from $3.9 million in 2018. On a per boe basis it was 15%
lower at $4.47/boe in 2019 compared to $5.28/boe in 2018. The decreases are attributable to decreased activity related to well workover
projects.
For the year ended December 31, 2019, net operating expense totaled $12.9 million, an 18% decrease from the $15.7 million in 2018. The
decrease is attributable to 8% lower production and decreased activity related to facility and well workover projects. On a per boe basis it was
$4.25/boe for the year ended December 31, 2019, 11% lower than the $4.75/boe in 2018. The decrease is related to lower non-routine
expenditures.
Page |14
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, 2019
Three months ended
December 31, 2018
Twelve months ended
December 31, 2019
Twelve months ended
December 31, 2018
991
1.30
855
1.17
3,814
1.26
3,789
1.15
Petrus pays commodity and demand charges for transporting its gas on pipeline systems. The Company also incurs trucking costs on the portion
of its oil and natural gas liquids production that is not pipeline connected. Fourth quarter 2019 transportation expense was $1.0 million or
$1.30/boe compared to $0.9 million or $1.17/boe in 2018. The increase in transportation expense is attributed to increased tolls on midstream
pipelines, increased NGL volume transported via truck and 5% higher production. For the year ended December 31, 2019, transportation
expense totaled $3.8 million, or $1.26/boe, compared to $3.8 million or $1.15/boe in 2018. The increases are attributed to increased trucking
costs and 14% decreased production (on a per boe basis).
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:
General and Administrative Expense ($000s)
Three months ended
December 31, 2019
Three months ended
December 31, 2018
Twelve months ended
December 31, 2019
Twelve months ended
December 31, 2018
Personnel, consultants and directors
Administrative expenses
Regulatory and professional expenses
Gross general and administrative expense
Capitalized general and administrative expense
Overhead recoveries
General and administrative expense
General and administrative expense ($/boe)
1,139
613
218
1,970
(439)
(72)
1,459
1.91
1,248
680
320
2,248
(487)
(696)
1,065
1.46
3,875
1,657
685
6,217
(1,506)
(1,067)
3,644
1.20
4,610
2,588
1,031
8,229
(1,718)
(1,327)
5,184
1.57
Fourth quarter gross G&A expense was 12% lower than the prior year ($2.0 million in 2019 compared to $2.2 million in 2018) which is attributed
to lower office rent which is now accounted for as finance and depreciation expense under IFRS 16 as well as lower office expenses and staffing
costs due to fewer personnel. Fourth quarter 2019 G&A expense (net) was $1.5 million or $1.91/boe, compared to $1.1 million or $1.46/boe
in 2018. The increases in 2019 on a net basis are attributed to lower capitalized G&A and overhead recoveries due to lower capital activity.
For the year ended December 31, 2019, gross G&A expense was $6.2 million compared to $8.2 million in 2018 which represents a 24% decrease.
Annual G&A expense (net) in 2019 was $3.6 million or $1.20/boe compared to $5.2 million or $1.57/boe in 2018 (24% decrease on a per boe
basis despite 8% lower annual production). The decreases are attributed to lower office rent (IFRS 16), and fewer personnel resulting in lower
office and personnel expenses.
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, 2019
Three months ended
December 31, 2018
Twelve months ended
December 31, 2019
Twelve months ended
December 31, 2018
Gross share-based compensation expense
Capitalized share-based compensation expense
Share-based compensation expense
125
34
159
329
(70)
259
529
(128)
401
858
(282)
576
Fourth quarter net share-based compensation expense was $0.2 million in 2019, which is 39% lower than the $0.3 million in 2018. For the
year ended December 31, 2019, net share-based compensation expense was $0.4 million, which is 30% lower than the $0.6 million in 2018.
Page |15
FINANCE EXPENSE
The following table illustrates the Company’s finance expense which includes cash and non-cash expenses:
Finance Expense ($000s)
Interest expense
Deferred financing costs
Accretion on decommissioning obligations
Total finance expense
Three months ended
December 31, 2019
Three months ended
December 31, 2018
Twelve months ended
December 31, 2019
Twelve months ended
December 31, 2018
1,939
121
176
2,236
2,370
174
224
2,768
8,241
495
777
9,513
8,273
637
887
9,797
Fourth quarter total finance expense was $2.2 million in 2019, comprised of $0.2 million of non-cash accretion of its decommissioning
obligations, $1.9 million of cash interest expense and $0.1 million of deferred financing fee amortization, both of which are related to the RCF
and Term Loan. In the fourth quarter of 2018, the Company incurred total finance expense of $2.8 million, comprised of $0.2 million in non-
cash accretion of its decommissioning obligation, $2.4 million cash interest expense and $0.2 million of deferred financing fee amortization.
The decrease in total finance expense from the prior year is due to lower RCF balance.
The Company incurred total finance expense of $9.5 million for the year ended December 31, 2019, which is lower than the $9.8 million for
2018. The decrease is due to the lower RCF balance outstanding.
DEPLETION AND DEPRECIATION
The following table compares depletion and depreciation expense recorded in the reporting periods shown:
Depletion and Depreciation Expense ($000s)
Three months ended
December 31, 2019
Three months ended
December 31, 2018
Twelve months ended
December 31, 2019
Twelve months ended
December 31, 2018
Depletion and depreciation expense
Depletion and depreciation expense ($/boe)
8,735
11.45
8,679
11.89
36,564
12.06
40,423
12.28
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.
Fourth quarter depletion and depreciation expense in 2019 was $8.7 million or $11.45/boe, compared to $8.7 million or $11.89/boe in 2018.
For the year ended December 31, 2019, the Company recorded $36.6 million or $12.06/boe, compared to $40.4 million or $12.28/boe in 2018.
The decreases in depletion and depreciation expense per boe are attributed to the impairment recorded in the third quarter of 2019.
IMPAIRMENT
The following table illustrates impairment losses recorded in the reporting periods:
Impairment ($000s)
Impairment
Total
Three months ended
December 31, 2019
Three months ended
December 31, 2018
Twelve months ended
December 31, 2019
Twelve months ended
December 31, 2018
—
—
—
—
24,655
24,655
—
—
Petrus has certain CGUs that are not core to the Company. As such, a sales process has been in place 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, Petrus recognized an impairment loss of $24.7 million during the year ended December 31, 2019 (nil in 2018).
Page |16
SHARE CAPITAL
The Company's authorized share capital consists of an unlimited number of 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, 2019
Three months ended
December 31, 2018
Twelve months ended
December 31, 2019
Twelve months ended
December 31, 2018
Weighted average Common Shares outstanding
Basic
Fully diluted
Common shares outstanding
Basic
Fully diluted
Stock options outstanding
49,469
49,469
49,469
49,469
2,362
49,492
49,492
49,492
49,492
3,083
49,472
49,472
49,469
49,469
2,362
49,492
49,492
49,492
49,492
3,083
At December 31, 2019, the Company had 49,469,358 common shares and 2,361,958 stock options outstanding.
The Company issued 1,386,357 stock options during the year ended December 31, 2019:
(a) 390,000 stock options were issued on March 22, 2019 at an exercise price of $0.45.
(b) 300,000 stock options were issued on June 10, 2019 at an exercise price of $0.32.
(c) 696,357 stock options were issued on December 27, 2019 at an exercise price of $0.26.
The Company has a deferred share unit plan in place whereby it may issue deferred share units ("DSUs") to directors of the Company. At
December 31, 2019, 1,177,510 (December 31, 2018 – 382,796) DSUs were issued and outstanding. Each DSU entitles the participants to
receive, at the Company's discretion, either Common Shares or cash equivalent to the number of DSUs multiplied by the current trading price
of the equivalent number of common shares. All DSUs vest and become payable upon retirement of the director.
LIQUIDITY AND CAPITAL RESOURCES
Petrus has two debt instruments outstanding. The first is a reserve-based, senior secured revolving credit facility with a syndicate of lenders,
which is the RCF. The second is the Term Loan.
(a) Revolving Credit Facility
At December 31, 2019, the RCF was comprised of a $20 million operating facility and a $78 million syndicated term-out facility. Lender
consent is required for borrowings exceeding $93 million. The syndicated term-out facility and the amount of borrowing that requires
lender consent will be reduced by $2 million on March 31, 2020. The Company has provided collateral by way of a debenture over all
of the present and after acquired property of the Company. The RCF's maturity date is May 31, 2020 which was set prior to the Term
Loan maturity of October 8, 2020 due to the inter-creditor relationship between the RCF and the Term Loan. The Company requires
an extension or refinancing of its Term Loan before the syndicate of lenders will contemplate an extension to the RCF.
At December 31, 2019, the Company had a $0.7 million letter of credit outstanding against the RCF (December 31, 2018 – $0.7 million)
and had drawn $92.3 million against the RCF (December 31, 2018 – $97.0 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, 2020. In the event that the lenders reduce the borrowing
base below the amount drawn at the time of redetermination, the Company has 60 days to eliminate any shortfall by repaying amounts
in excess of the new re-determined borrowing base.
(b) Term Loan
At December 31, 2019, the Company had a $35 million (December 31, 2018 – $35 million) Term Loan outstanding (excluding $0.3 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 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.
Page |17
Financial Covenants
The RCF and the Term Loan carry financial covenants that are described in note 8 of the Company's December 31, 2019 audited annual
consolidated financial statements. The Company was in compliance with all financial covenants at December 31, 2019.
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 (including current portion thereof) and risk management liabilities.
At December 31, 2019, the Company had a working capital deficiency (excluding non-cash risk management assets and liabilities) of $123.9
million which has increased by $115.9 million from $8.0 million on December 31, 2018. The change is attributed to the Company's borrowings
under its RCF and Term Loan which were reclassified from non-current to current liabilities as they are each due within one year as at December
31, 2019. The RCF's maturity date is May 31, 2020 due to the inter-creditor relationship between the RCF and the Company's Term Loan which
is due October 8, 2020. The Company requires an extension or refinancing of its Term Loan before the syndicate of lenders will contemplate
an extension. The reclassification of the RCF and Term Loan have no impact on the Company's debt covenants and the Company continues to
be compliant with each of its covenants. Management is actively engaged with the RCF syndicate of lenders and the Term Loan lender and we
believe that the RCF and Term Loan will each be extended prior to May 31, 2020. Upon the extension of the RCF and Term Loan, the working
capital deficiency will be eliminated. The Company continues its efforts to divest certain non-core assets to improve the balance sheet.
The currently challenged economic environment could result in adverse changes in cash flows, net debt balances, reduction in the borrowing
base of the Company's RCF, breach of its financial covenants and there is no guarantee that the RCF and Term Loan will each be extended prior
to their respective maturities of May 31, 2020 and October 8, 2020. Accordingly, there is a material uncertainty that may cast significant doubt
on the Company’s ability to continue as a going concern. However, the Company remains in compliance with all financial covenants pertaining
to its debt, and based on current available information relating to future production volumes, forward commodity pricing, future costs including
capital, operating and general and administrative, forward exchange rates, interest rates and taxes, all of which are subject to measurement
uncertainty, management expects to comply with all financial covenants during the subsequent 12 month period.
The following are the contractual maturities of financial liabilities as at December 31, 2019:
$000s
Accounts payable and accrued liabilities
Risk management liability
Bank indebtedness and long term debt(1)
Lease obligations
Total
(1)Excludes deferred finance fees.
Total
11,362
1,753
127,250
1,398
141,763
< 1 year
11,362
1,679
127,250
219
140,510
The commitments for which the Company is responsible are as follows:
$000s
Firm service transportation
Total
16,871
< 1 year
2,016
1-5 years
11,691
1-5 years
—
74
—
1,179
1,253
> 5 years
3,164
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.
For a more in-depth discussion of risk management, see notes 11 and 16 of the Company’s December 31, 2019 consolidated financial statements.
Page |18
CAPITAL EXPENDITURES
Capital expenditures (excluding acquisitions and dispositions) totaled $4.4 million in the fourth quarter of 2019, compared to $12.7 million in
2018. The Company participated in the drilling activities for 3 (0.05 net) Cardium light oil wells in Ferrier during the fourth quarter and recognized
capital expenditures related to the 4 (1.55 net) Cardium light oil wells drilled during the third quarter.
Capital expenditures (excluding acquisitions and dispositions) totaled $18.1 million in the year ended December 31, 2019, compared to $24.1
million in 2018. The decrease from the prior year is attributed to the Company's strategy to prioritize debt repayment and moderate capital
spending.
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
Land and lease
Office
Capitalized general and administrative expense
Total capital expenditures
Gross (net) wells spud
Three months ended
December 31, 2019
Three months ended
December 31, 2018
Twelve months ended
December 31, 2019
Twelve months ended
December 31, 2018
3,604
283
17
8
439
4,351
3 (0.5)
10,503
1,636
23
60
438
12,660
6 (2.7)
12,871
3,635
37
24
1,506
18,073
10 (3.1)
16,510
4,177
1,635
58
1,718
24,098
10 (4.3)
During the year ended December 31, 2019, Petrus divested of non-core assets for approximately $0.7 million. Petrus divested non-core assets
for approximately $0.4 million during the year ended December 31, 2018.
The following table summarizes the dispositions for the reporting periods indicated:
Dispositions ($000s)
Dispositions
Total dispositions
Three months ended
December 31, 2019
Three months ended
December 31, 2018
Twelve months ended
December 31, 2019
Twelve months ended
December 31, 2018
—
—
6
6
651
651
448
448
Page |19
SUMMARY OF QUARTERLY RESULTS
($000s unless otherwise noted)
Dec. 31,
2019
Sept. 30,
2019
Jun. 30,
2019
Mar. 31,
2019
Dec. 31,
2018
Sept. 30,
2018
Jun. 30,
2018
Mar. 31,
2018
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
32,641
30,998
32,350
32,145
30,480
33,461
39,126
45,543
1,834
1,018
8,292
1,247
1,372
7,785
1,679
1,576
8,647
1,704
1,444
8,505
1,358
1,496
7,934
1,243
1,519
8,338
1,484
1,241
9,246
1,530
1,475
10,596
762,874
716,220
786,819
765,488
730,819
767,095
841,316
953,598
20,998
12,517
17,652
20,231
16,064
20,030
19,321
25,301
(2,218)
(1,182)
(1,355)
(2,359)
(2,436)
(2,391)
(2,137)
(4,674)
Net oil and natural gas revenue
18,780
11,335
16,297
17,872
13,628
17,639
17,184
20,627
Transportation expense
Operating expense
Operating netback
Realized gain (loss) on derivatives
Other income
General and 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 average shares outstanding (000s)
Basic
Fully diluted
Total assets
Net debt
(991)
(893)
(959)
(971)
(855)
(749)
(988)
(3,407)
(3,181)
(3,405)
(2,880)
(3,851)
(3,800)
(3,841)
(1,197)
(4,160)
14,382
7,261
11,933
14,021
8,922
13,090
12,355
15,270
(1,417)
7
(1,459)
(1,939)
(314)
9,260
360
21
(776)
(800)
78
(530)
513
—
(879)
(2,230)
(2,126)
(1,945)
(209)
4,427
(189)
(137)
8,366
11,573
(573)
268
(1,065)
(2,370)
(152)
5,030
(2,061)
69
(1,317)
(1,941)
(155)
7,685
(625)
103
(1,372)
(2,097)
—
298
—
(1,430)
(1,865)
(168)
8,364
12,105
20,998
12,517
17,652
20,231
16,064
20,030
19,321
25,301
0.42
0.42
0.25
0.25
0.36
0.36
0.41
0.41
0.32
0.32
0.40
0.40
0.39
0.39
0.51
0.51
(3,176)
(29,569)
2,863
(12,138)
21,063
(8,048)
(10,615)
(5,684)
(0.06)
(0.06)
(0.60)
(0.60)
0.06
0.06
(0.25)
(0.25)
0.43
0.43
(0.16)
(0.16)
(0.21)
(0.21)
(0.11)
(0.11)
49,469
49,469
49,469
49,469
49,469
49,469
49,469
49,469
49,492
49,492
49,492
49,492
49,492
49,492
49,492
49,492
49,469
49,469
49,469
49,469
49,469
49,469
49,483
49,483
49,492
49,492
49,492
49,492
49,492
49,492
49,492
49,492
289,225
296,367
328,912
336,974
341,820
322,335
330,359
343,161
(123,744)
(128,553)
(130,619)
(136,382)
(139,214)
(131,603)
(135,111)
(142,238)
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 10,596 boe/d in the first quarter of 2018 to 8,292 boe/d in the fourth quarter of 2019. The 22% production decrease
is attributable to Petrus' shift in focus to liquids production growth in order to maximize value in light of the current natural gas commodity
price environment as well as certain development activity postponed to prioritize debt repayment. In addition the decrease is due to certain
production volume in the Foothills area being shut-in due to uneconomic natural gas pricing.
Commodity price improvements enable higher reinvestment in exploration, development and acquisition activities 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 |20
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, 2019
December 31, 2018
December 31, 2017
71,398
1.44
1.44
(42,176)
(0.85)
(0.85)
49,469
49,469
49,469
49,469
289,225
42,346
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
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, 2019.
OTHER FINANCIAL INFORMATION
Significant accounting policies
The Company’s significant accounting policies can be read in note 3 of the Company’s consolidated financial statements as at and for the year
ended December 31, 2019.
New standards and interpretations
The Company's discussion on new standards and interpretations can be read in note 3 of the Company’s consolidated financial statements
as at and for the period ended December 31, 2019.
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, 2019 and have concluded that the Company's DC&P are effective at December 31, 2019 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
Page |21
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, 2019, 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, 2019. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that
as at December 31, 2019, 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
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" and "net debt". 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, in the following table, 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 loss on financial derivatives
Other income
General & administrative expense
Interest expense
Decommissioning expenditures
Funds flow and corporate netback
Three months ended
Dec. 31, 2019
Three months ended
Dec. 31, 2018
Twelve months ended
December 31, 2019
Twelve months ended
December 31, 2018
$000s
$/boe
$000s
$/boe
$000s
$/boe
$000s
$/boe
20,998
(2,218)
18,780
(991)
(3,407)
14,382
(1,417)
7
(1,459)
(1,939)
(314)
9,260
27.52
(2.91)
24.61
(1.30)
(4.47)
18.84
(1.86)
—
(1.91)
(2.54)
(0.41)
12.12
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
71,398
(7,114)
64,284
(3,814)
(12,873)
47,597
(1,344)
106
(3,644)
(8,241)
(849)
33,625
23.55
(2.35)
21.20
(1.26)
(4.25)
15.69
(0.44)
0.03
(1.20)
(2.72)
(0.28)
11.08
80,716
(11,638)
69,078
(3,789)
(15,652)
49,637
(2,961)
440
(5,184)
(8,273)
(475)
33,184
24.52
(3.54)
20.98
(1.15)
(4.75)
15.08
(0.90)
0.13
(1.57)
(2.51)
(0.14)
10.09
Page |22
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, right-of-use lease obligations, 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
As at December 31, 2019 As at December 31, 2018
14,620
(138,364)
—
(123,744)
14,035
(21,827)
(131,422)
(139,214)
Net debt
(1)Adjusted for unrealized risk management assets, liabilities, lease obligations and unrealized deferred share unit liabilities.
OIL AND GAS DISCLOSURES
Our oil and gas reserves statement for the year ended December 31, 2019, 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.
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 reserves 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. In 2019, the P+P FD&A and F&D costs including
changes in FDC can generate non meaningful information because acquisitions and dispositions can have a significant impact on our ongoing
reserves replacement costs.
Reserve Life Index
Reserve life index is defined as total reserves by category divided by teh 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.
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 or other purposes.
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 consolidated financial statements as at and for the twelve months ended December 31, 2019. 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
Page |23
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.
In particular, forward-looking statements included in this MD&A include, but are not limited to, statements with respect to: the anticipated
impacts of TSP; continued expansion of the NGTL system and low Alberta natural gas storage levels; Petrus' ability to modify its operations;
Petrus' business plan and expected debt repayment in 2020 and the anticipated results thereof; the Closing of the Disposition, including the
timing and results therof; Petrus' expected drilling and operations activities in 2020; the results of Petrus' 2019 capital plan and the targets
thereof; Petrus' 2020 capital plan and the expected results thereof; expectations regarding the adequacy of Petrus' liquidity and the funding
of its financial liabilities; Petrus' ability to extend the RCF and Term Loan and the timing thereof; the impact of the current economic environment
on Petrus; the performance characteristics of the Company's crude oil, NGL and natural gas properties; future prospects; the focus of and
timing of capital expenditures; access to debt and equity markets; 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.
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.
This MD&A contains future-oriented financial information and financial outlook information (collectively, "FOFI") about Petrus' prospective
results of operations including, without limitation, its ability to repay debt, which are subject to the same assumptions, risk factors, limitations,
and qualifications as set forth above. Readers are cautioned that the assumptions used in the preparation of such information, although
considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on FOFI. Petrus'
actual results, performance or achievement could differ materially from those expressed in, or implied by, these FOFI, or if any of them do so,
what benefits Petrus will derive therefrom. Petrus has included the FOFI in order to provide readers with a more complete perspective on
Petrus' future operations and such information may not be appropriate for other purposes.
These forward-looking statements and FOFI are made as of the date of this MD&A and the Company disclaims any intent or obligation to update
any forward-looking statements and FOFI, 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 |24
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 |25
CONSOLIDATED ANNUAL FINANCIAL STATEMENTS
As at and for the years ended December 31, 2019 and 2018
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, 2019 and 2018, 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, 2019 and 2018, 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.
Material uncertainty related to going concern
We draw attention to note 2(a) in the consolidated financial statements, which indicates that the Company’s continued successful operations are dependent
on its ability to restructure its debt or obtain additional financing. As stated in Note 2(a) these events or conditions indicate that a material uncertainty exists
that casts significant doubt on the Company’s ability to continue as a going concern. Our opinion is not modified in respect of this matter.
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
February 18, 2020
CONSOLIDATED BALANCE SHEETS
(Presented in 000’s of Canadian dollars)
As at
December 31, 2019
December 31, 2018
ASSETS
Current
Cash
Deposits and prepaid expenses
Accounts receivable (note 16)
Risk management asset (note 11)
Total current assets
Non-current
Risk management asset (note 11)
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
Current portion of long term debt (note 8)
Accounts payable and accrued liabilities (note 16)
Risk management liability (note 11)
Lease obligations (note 9)
Total current liabilities
Non-current liabilities
Long term debt (note 8)
Lease obligations (note 9)
Decommissioning obligation (note 10)
Risk management liability (note 11)
Total liabilities
Shareholders’ equity
Share capital (note 12)
Contributed surplus
Deficit
Total shareholders' equity
Total liabilities and shareholders' equity
Going concern (note 2)
Commitments (note 20)
See accompanying notes to the consolidated financial statements
Approved by the Board of Directors,
(signed) “Don T. Gray”
Don T. Gray
Chairman
256
1,328
13,036
—
14,620
11
36,116
238,478
289,225
—
127,002
11,362
1,679
136
140,179
—
1,013
41,259
74
182,525
430,119
9,112
(332,531)
106,700
289,225
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
(signed) “Donald Cormack”
Donald Cormack
Director
Page |29
CONSOLIDATED STATEMENTS OF NET LOSS AND COMPREHENSIVE LOSS
(Presented in 000’s of Canadian dollars, except per share amounts)
REVENUE
Oil and natural gas revenue (note 21)
Royalty expense
Net oil and natural gas revenue
Other income
Net gain (loss) on financial derivatives (note 11)
EXPENSES
Operating (note 14)
Transportation
General and administrative (note 15)
Share-based compensation (note 12)
Finance (note 18)
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 13)
See accompanying notes to the consolidated financial statements
Year ended
December 31, 2019
Year ended
December 31, 2018
71,398
(7,114)
64,284
106
(12,617)
51,773
12,873
3,814
3,644
401
9,513
2,004
36,564
481
24,655
93,949
(42,176)
(0.85)
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)
Page |30
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Presented in 000’s of Canadian dollars)
Balance, December 31, 2017
Net loss
Share-based compensation
Balance, December 31, 2018
Net loss
Share-based compensation (note 12)
Balance, December 31, 2019
See accompanying notes to the consolidated financial statements
Share
Capital
430,119
—
—
430,119
—
—
430,119
Contributed
Surplus
7,680
—
704
8,384
—
728
9,112
Deficit
(287,071)
(3,284)
—
(290,355)
(42,176)
—
(332,531)
Total
150,728
(3,284)
704
148,148
(42,176)
728
106,700
Page |31
Year ended
December 31, 2019
Year ended
December 31, 2018
(42,176)
401
11,273
1,272
36,564
24,655
2,004
481
(849)
33,625
(5,803)
27,822
(4,749)
(381)
—
(400)
196
(5,334)
—
—
651
(394)
(17,655)
(24)
(4,873)
(22,295)
193
63
256
8,241
(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
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 12)
Unrealized loss (gain) on financial derivatives (note 11)
Non-cash finance expenses (note 18)
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 10)
Funds flow
Change in operating non-cash working capital (note 19)
Cash flows from operating activities
FINANCING ACTIVITIES
Repayment of revolving credit facility
Repayment of bank indebtedness
Transaction costs on debt
Repayment of lease liabilities (note 9)
Change in financing non-cash working capital (note 19)
Cash flows used in financing activities
INVESTING ACTIVITIES
Property and equipment acquisitions (note 5)
Property and equipment dispositions (note 5)
Exploration and evaluation asset dispositions (acquisition) (note 5)
Exploration and evaluation asset expenditures (note 6)
Petroleum and natural gas property expenditures (note 7)
Other capital expenditures
Change in investing non-cash working capital (note 19)
Cash used in investing activities
Increase in cash
Cash, beginning of period
Cash, end of period
Cash interest paid (note 18)
See accompanying notes to the interim consolidated financial statements
Page |32
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the years ended December 31, 2019 and 2018
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 consist of 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, 2019 and 2018, were approved by the Company’s Audit Committee and Board of
Directors on February 18, 2020.
2. BASIS OF PRESENTATION
(a) Going Concern
These financial statements have been prepared in accordance with generally accepted accounting principles applicable to a going concern, which assumes that
the Company will be able to realize its assets and discharge its liabilities in the normal course of business.
The Company's Term Loan is due October 8, 2020. The revolving credit facility ("RCF")'s maturity date is May 31, 2020 due to the inter-creditor relationship
between the two debt instruments. The Company requires an extension or refinancing of its Term Loan before the syndicate of lenders will contemplate an
extension of the RCF. The borrowings under the RCF and the Term Loan are classified as current liabilities in the December 31, 2019 consolidated financial
statements which has no impact on the debt covenants and the Company remains in compliance with each of its covenants. However, the reclassification of
the debt instruments resulted in a working capital deficiency (excluding non-cash risk management assets and liabilities) of $123.9 million as of December 31,
2019. For the year ended December 31, 2019 the Company generated funds flow of $33.6 million and reduced its debt. Management is actively engaged with
the RCF syndicate of lenders and the Term Loan lender. However, there can be no certainty as to the ability of the Company to successfully restructure its RCF
and Term Loan or obtain new financing.
Accordingly, there is a material uncertainty that may cast significant doubt on the Company’s ability to continue as a going concern. These financial statements
do not include adjustments to the recoverability and classification of recorded asset and liabilities and related expenses that might be necessary should the
Company be unable to continue as a going concern and therefore be required to realize its assets and liquidate its liabilities and commitments in other than
the normal course of business at amounts different from those in the accompanying consolidated financial statements. Such adjustments could be material.
(b) 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”).
(c) 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.
(d) 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.
(e) 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
Page |33
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 of variables 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
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.
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.
Page |34
(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).
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.
Page |35
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).
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 forecast 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.
(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.
Page |36
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
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 Company, the fair value of the DSUs is recognized as stock-based
compensation expense, with a corresponding increase in contributed surplus.
(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.
(o) New standards and interpretations
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 are 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 re-
measurement 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 had adopted IFRS 16 using the modified
retrospective approach.
On initial adoption, the Company elected to use the following practical expedients permitted under the standard:
1.
2.
3.
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 Company has identified ROU assets which are included in property plant and equipment and lease liabilities primarily related to office space. The
recognition of the present value of minimum lease payments resulted in an additional $0.7 million of right-of-use assets and associated lease liabilities
as initial transition adjustment on January 1, 2019. The Company has recognized lease liabilities in relation to lease arrangements previously disclosed
Page |37
as operating lease commitments under IAS 17 that meet the criteria of a lease under IFRS 16. Upon recognition, the Company’s weighted average
incremental borrowing rate used in measuring lease liabilities was 7.5 percent. Refer to note 9 for additional information.
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.
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
Acquisition and disposal
During the year ended December 31, 2019, the Company disposed of certain exploration and evaluation assets for $0.7 million and recorded a net loss of $0.5
million from this disposition.
During the year ended December 31, 2018, the Company 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.
Asset exchange agreement
On March 13, 2018, the Company 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.
Page |38
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
6. EXPLORATION AND EVALUATION ASSETS
The components of the Company’s exploration and evaluation ("E&E") assets are as follows:
$000s
Balance, December 31, 2017
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)
Balance, December 31, 2018
Additions
Disposition (note 5)
Exploration and evaluation expense
Capitalized G&A
Capitalized share-based compensation (note 12)
Impairment
Transfers to property, plant and equipment (note 7)
Balance, December 31, 2019
1,086
3,231
(471)
3,846
1,013
2,852
(224)
3,641
43,197
1,057
402
(1,938)
429
70
(58)
(749)
42,410
18
(1,177)
(2,004)
376
32
(3,086)
(453)
36,116
For the year ended December 31, 2019, the Company incurred exploration and evaluation expense of $2.0 million, which relates to expired and nearly expired
undeveloped, non-core land (2018 – $1.9 million).
During the year ended December 31, 2019, the Company capitalized $0.4 million of general and administrative expenses (“G&A”) (2018 – $0.4 million) and
$0.03 million of non-cash share-based compensation directly attributable to exploration activities (2018 – $0.07 million).
As at December 31, 2019, the book value of the Company's net assets was greater than its market capitalization. The Company considered this to be an indicator
of impairment and performed an impairment test on all CGUs. The Company determined the fair value less costs of disposal for its two non-core CGUs based
on interest expressed during the sales process for its Foothills and Central Alberta assets. The Company recorded an impairment loss of $3.1 million on its E&E
assets in the Foothills and Central Alberta CGU during the year ended December 31, 2019. For the Ferrier CGU, no impairment charge was required.
Page |39
7. PROPERTY, PLANT AND EQUIPMENT
The components of the Company’s property, plant and equipment assets are as follows:
$000s
Balance, December 31, 2017
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 10)
Balance, December 31, 2018
Additions
Transition adjustment of right of use asset(1)
Addition of right of use asset(1)
Capitalized G&A
Capitalized share-based compensation (note 12)
Transfers from exploration and evaluation assets (note 6)
Depletion & depreciation
Increase in decommissioning provision (note 10)
Impairment
Balance, December 31, 2019
(1)Right of use asset pertains to corporate office lease.
Cost
779,298
20,549
2,935
(3,503)
1,288
212
749
—
(438)
801,090
16,550
742
709
1,129
97
453
—
1,091
—
821,861
Accumulated
DD&A
(484,827)
—
—
—
—
—
—
(40,423)
—
(525,250)
—
—
—
—
—
(36,564)
—
(21,569)
(583,383)
Net book value
294,471
20,549
2,935
(3,503)
1,288
212
749
(40,423)
(438)
275,840
16,550
742
709
1,129
97
453
(36,564)
1,091
(21,569)
238,478
At December 31, 2019, estimated future development costs of $267.7 million (2018 – $291.2 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, 2019, the Company capitalized
$1.1 million of general and administrative expenses (“G&A”) (2018 – $1.3 million) and non-cash share-based compensation of $0.1 million (2018 – $0.2 million),
directly attributable to development activities.
As at December 31, 2019, the book value of the Company's net assets was greater than its market capitalization. The Company considered this to be an indicator
of impairment and performed an impairment test of each of its CGUs. The Company determined the fair value less costs of disposal for its two non-core CGUs
based on interest expressed during the sales process for its Foothills and Central Alberta assets. The Company recorded an impairment loss of $21.6 million
on its PP&E assets in the Foothills and Central Alberta CGUs during the year ended December 31, 2019. For the Ferrier CGU the recoverable amount exceeded
the carrying value therefore no impairment was recorded. The recoverable amount, a level 3 input on the fair value hierarchy (see note 4), was estimated at
fair value less costs of disposal based on proved plus probable reserves and applying an after-tax discount rate ranging from 9% to 10% on the estimated future
cash flow. The Company uses the following forward commodity price estimates:
Year
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
Canadian Light Sweet
AECO $/MMbtu
73.84
78.51
78.73
80.30
81.91
83.54
85.21
86.92
88.66
90.43
92.24
2.04
2.27
2.81
2.89
2.98
3.06
3.15
3.24
3.33
3.42
3.51
Escalation rate of 2.0% thereafter.
At December 31, 2019, the carrying balance of the right of use asset was $1.2 million.
Page |40
8. DEBT
Petrus has 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, 2019, the RCF was comprised of a $20 million operating facility and a $78 million syndicated term-out facility. Lender consent is
required for borrowings exceeding $93 million. The syndicated term-out facility and the amount of borrowing that requires lender consent will be
reduced by $2 million on March 31, 2020. The Company has provided collateral by way of a debenture over all of the present and after acquired property
of the Company. The RCF's maturity date is May 31, 2020 which was set prior to the Term Loan maturity of October 8, 2020 due to the inter-creditor
relationship between the RCF and the Term Loan. The Company requires an extension or refinancing of its Term Loan before the syndicate of lenders
will contemplate an extension to the RCF.
At December 31, 2019, the Company had a $0.7 million letter of credit outstanding against the RCF (December 31, 2018 – $0.7 million) and had drawn
$92.3 million against the RCF (December 31, 2018 – $97.0 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, 2020. In the event that the lenders reduce the borrowing base below the amount drawn at the time of redetermination,
the Company has 60 days to eliminate any shortfall by repaying amounts in excess of the new re-determined borrowing base.
(b) Term Loan
At December 31, 2019 the Company had a $35 million (December 31, 2018 – $35 million) Term Loan outstanding (excluding $0.3 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 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.
Liquidity
At December 31, 2019, the Company had a working capital deficiency (excluding non-cash risk management assets and liabilities) of $123.9 million which has
increased due to the reclassification of the Company's borrowings under its RCF and Term Loan. See note 2(a).
However, the Company remains in compliance with all financial covenants pertaining to its debt, and based on current available information relating to future
production volumes, forward commodity pricing, future costs including capital, operating and general and administrative, forward exchange rates, interest rates
and taxes, all of which are subject to measurement uncertainty, management expects to comply with all financial covenants during the subsequent 12 month
period.
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.
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.
The Company is unable to borrow amounts greater than the RCF limit;
Page |41
b.
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 Total Debt at the date of the annual borrowing base redetermination which will take place
on or before May 31, 2020.
The key financial covenants as at December 31, 2019 are summarized in the following table. At December 31, 2019 the Company is in compliance with all
financial covenants.
Financial Covenant Description
Required Ratio
As at December 31, 2019
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, 2019 reserve report evaluated by Sproule Associates Ltd.
Over 1.00
Over 1.25
Over 1.00
Under 3.50
9. LEASES
The Company's lease obligations are as follows:
$000s
Balance, January 1, 2019
Additions
Finance expense
Lease payments
Balance, December 31, 2019
The Company's future commitments associated with its lease obligations are as follows:
$000s
Less than 1 year
1 to 3 years
4 to 5 years
After 5 years
Total lease payments
Amounts representing finance expense
Present value of lease obligation
Current portion of lease obligation
Non-current portion of lease obligation
10. DECOMMISSIONING OBLIGATION
1.73
1.90
1.08
2.99
742
709
98
(400)
1,149
As at December 31, 2019
219
810
369
—
1,398
(249)
1,149
136
1,013
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 1.76 percent and an inflation rate of 1.75 percent (2018 – 2.13 percent and 2.00 percent, respectively). Changes in estimates
in 2018 and 2019 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 $41.3 million as at December 31, 2019 ($40.2 million at December 31, 2018).
The undiscounted, uninflated total future liability at December 31, 2019 is $41.4 million ($41.6 million at December 31, 2018). The payments are expected to
be incurred over the operating lives of the assets.
Page |42
The following table reconciles the decommissioning liability:
$000s
Balance, December 31, 2017
Property acquisitions
Property dispositions
Liabilities incurred
Liabilities settled
Change in estimates
Accretion expense
Balance, December 31, 2018
Property dispositions
Liabilities incurred
Liabilities settled
Change in estimates
Accretion expense
Balance, December 31, 2019
11. FINANCIAL RISK MANAGEMENT
40,654
224
(629)
393
(475)
(830)
887
40,224
(24)
729
(849)
402
777
41,259
The Company utilizes commodity contracts as a risk management technique to mitigate exposure to commodity price volatility. The following table
summarizes the financial derivative contracts Petrus had outstanding as at December 31, 2019:
Contract Period
Natural Gas Swaps
Jan. 1, 2020 to Mar. 31, 2020
Jan. 1, 2020 to Mar. 31, 2021
Nov. 1, 2019 to Oct. 31, 2020
Jan. 1, 2020 to Oct. 31, 2021
Apr. 1, 2020 to Oct. 31, 2020
Apr. 1, 2020 to Mar. 31, 2021
Nov. 1, 2020 to Mar. 31, 2021
Apr. 1, 2021 to Oct. 31, 2021
Contract Period
Crude Oil Swaps
Jan. 1, 2020 to Mar. 31, 2020
Jan. 1, 2020 to Jun. 30, 2020
Jan. 1, 2020 to Dec. 31, 2020
Apr. 1, 2020 to Jun. 30, 2020
Jul. 1, 2020 to Sep. 30, 2020
Jul. 1, 2020 to Dec. 31, 2020
Oct. 1, 2020 to Dec. 31, 2020
Jan. 1, 2021 to Mar. 31, 2021
Jan. 1, 2021 to Jun. 30, 2021
Jul. 1, 2021 to Dec. 31, 2021
Contract Period
Interest Rate Swaps
Jan. 1, 2020 to Dec. 31, 2022
Type
Total Daily Volume (GJ)
Average Price (CDN$/GJ)
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
9,000
2,000
3,500
1,000
4,000
2,000
2,000
3,000
$1.91
$1.50
$1.58
$1.53
$1.52
$1.45
$1.98
$1.63
Type
Total Daily Volume (Bbl)
Average Price (CDN$/Bbl)
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
800
300
350
500
300
300
100
200
300
300
$70.20
$77.25
$76.70
$75.52
$77.86
$75.57
$68.26
$71.06
$74.02
$72.80
Type
Average Rate (%)
Notional Amount (000s CDN$)
Fixed rate
2.34
$20,000
Page |43
Risk management asset and liability:
$000s At December 31, 2019
Current commodity derivatives
Non-current commodity derivatives
$000s At December 31, 2018
Current commodity derivatives
Non-current commodity derivatives
Earnings impact of realized and unrealized gains (losses) on financial derivatives:
$000s
Realized loss on financial derivatives
Unrealized gain (loss) on financial derivatives
Net gain (loss) on financial derivatives
12. SHARE CAPITAL
Asset
—
11
11
6,786
2,749
9,535
Liability
1,679
74
1,753
—
—
—
Year ended
December 31, 2019
Year ended
December 31, 2018
(1,344)
(11,273)
(12,617)
(2,961)
7,510
4,549
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)
Number of Shares
Amount
Balance, December 31, 2017 and December 31, 2018
Cancelled(1)
Balance, December 31, 2019
430,119
—
430,119
(1)On February 4, 2019, 22,482 shares were cancelled pursuant to the Arrangement Agreement between Phoscan Chemical Corp. and Petrus Resources Ltd (and
the 3 year sunset clause therein).
49,491,840
(22,482)
49,469,358
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, 2019, 2,361,958 (December 31, 2018 – 3,082,880) stock options were outstanding. The summary of stock option activity is presented below:
Balance, December 31, 2017
Granted
Forfeited
Expired
Balance, December 31, 2018
Granted
Cancelled/forfeited
Expired
Balance, December 31, 2019
Exercisable, December 31, 2019
Number of stock
options
2,914,930
1,208,880
(492,410)
(548,520)
3,082,880
1,386,357
(707,069)
(1,400,210)
2,361,958
35,000
Weighted average
exercise price
$4.21
$1.14
$5.94
$3.43
$2.87
$0.33
$1.74
$4.20
$1.19
$15.13
Page |44
The following table summarizes information about the stock options granted since inception:
Range of Exercise Price
Stock Options Outstanding
Stock Options Exercisable
$0.26 - $0.86
$1.49 - $2.33
$14.00
Number
granted
1,493,468
833,490
35,000
2,361,958
Weighted
average
exercise price
$0.43
$2.02
$14.00
$1.75
Weighted
average
remaining life
(years)
2.62
2.02
0.11
1.69
Number
exercisable
—
—
35,000
35,000
Weighted
average
exercise price
—
—
$14.00
$14.00
Weighted
average
remaining life
(years)
—
—
0.11
0.11
During the year ended December 31, 2019 and the year ended December 31, 2018, the Company granted options which vest equally over three years, and
upon vesting, expire 30 business days thereafter. The weighted average fair value of each option granted during the year ended December 31, 2019 of $0.11
(2018 – $0.30) was estimated on the date of grant using the Black-Scholes pricing model with the following weighted average assumptions:
Risk free interest rate
Expected life (years)
Estimated volatility of underlying common shares (%)
Estimated forfeiture rate
Expected dividend yield (%)
2019
2018
1.57% - 1.83%
1.08 - 3.08
73% - 81%
20%
0%
1.70% - 1.90%
1.08 - 3.08
63% - 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, 2019, 739,046 DSUs were issued and outstanding. The Company recorded the DSUs in its share-
based compensation for the year ended December 31, 2019.
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
Deferred share units
Total share-based compensation
13. LOSS PER SHARE
Year ended
December 31, 2019
401
32
97
198
728
Year ended
December 31, 2018
576
70
212
—
858
Loss per share amounts are calculated by dividing the net loss for the year attributable to the common shareholders of the Company by the weighted average
number of common shares outstanding during the period.
Page |45
Net loss for the period ($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, 2019
Year ended
December 31, 2018
(42,176)
49,472
49,472
($0.85)
($0.85)
(3,284)
49,492
49,492
($0.07)
($0.07)
In computing diluted loss per share for the year ended December 31, 2019, 2,361,958 outstanding stock options and 739,046 DSUs were considered
(December 31, 2018 – 3,082,880 and 296,104, respectively), which were excluded from the calculation as their impact was anti-dilutive.
14. OPERATING EXPENSES
The Company’s operating expenses consisted of the following expenditures:
$000s
Fixed and variable operating expenses
Processing, gathering and compression charges
Total gross operating expenses
Overhead recoveries
Total net operating expenses
15. GENERAL AND ADMINISTRATIVE EXPENSES
The Company’s general and administrative expenses consisted of the following expenditures:
$000s
Gross general and administrative expense
Capitalized general and administrative expense
Overhead recoveries
General and administrative expense
16. FINANCIAL INSTRUMENTS
Risks associated with financial instruments
2019
10,668
3,167
13,835
(962)
12,873
2019
6,217
(1,506)
(1,067)
3,644
2018
13,084
3,602
16,686
(1,034)
15,652
2018
8,229
(1,718)
(1,327)
5,184
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 $13.0 million of accounts receivable outstanding
at December 31, 2019 (December 31, 2018 – $12.7 million), $5.7 million is owed from 3 parties (December 31, 2018 – $7.1 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,
2019, the Company had an allowance for doubtful accounts of $0.4 million (December 31, 2018 – $0.2 million). At December 31, 2019, 95% of Petrus’
accounts receivable were aged less than 120 days and 5% of Petrus' accounts receivable were aged greater than 120 days. The Company does not anticipate
any material 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, 2019, the Company had a $98 million RCF with a borrowing limit of $93 million, on which $92.3 million was drawn (December 31, 2018
– $97.0 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, 2020. See additional discussion in note 8.
Page |46
The following are the contractual maturities of financial liabilities as at December 31, 2019:
$000s
Accounts payable and accrued liabilities
Risk management liability
Bank indebtedness and long term debt(1)
Lease obligations
Total
(1)Excludes deferred finance fees.
Total
11,362
1,753
127,250
1,398
141,763
< 1 year
11,362
1,679
127,250
219
140,510
1-5 years
0
74
0
1,179
1,253
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. To manage exposure to interest rate volatility, the Company entered into interest rate swap contracts (note 11). A 1% increase in the Canadian
prime interest rate during the year ended December 31, 2019 would have increased net loss by approximately $1.1 million, respectively, which relates to interest
expense on the average outstanding RCF and Term Loan, net of any interest rate swaps to fix the interest rate on loans, during the year assuming that all other
variables remain constant (December 31, 2018 – increase net loss by $1.3 million). A 1% decrease in the Canadian prime interest rate during the year 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 11). 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, 2019, it was estimated that a $0.25/GJ decrease in the price of natural gas would have decreased net loss by $1.5 million (December 31,
2018 – $1.8 million). An opposite change in commodity prices would result in an opposite impact on net loss. As at December 31, 2019, it was estimated that
a $5.00/CDN WTI/bbl decrease in the price of oil would have decreased net loss by $2.0 million (December 31, 2018 – $4.0 million). An opposite change in
commodity prices would result in an opposite impact on net loss.
17. 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.
18. FINANCE EXPENSES
The components of finance expenses are as follows:
$000s
Cash:
Interest
Total cash finance expenses
Non-cash:
Deferred financing costs
Accretion on decommissioning obligations (note 10)
Total non-cash finance expenses
Total finance expenses
Page |47
2019
8,241
8,241
495
777
1,272
9,513
2018
8,273
8,273
637
887
1,524
9,797
19. 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
2019
(31)
196
(361)
(10,284)
(10,480)
(5,803)
196
(4,873)
2018
133
(18)
(1,087)
(4,110)
(5,082)
(4,764)
298
(615)
The following table reconciles the changes in liability resulting from financing activities:
$000s
Balance, December 31, 2018
Cash flows
Non-cash changes
Balance, December 31, 2019
Bank Indebtedness
380
(380)
—
—
Revolving Credit
Facility
97,000
(4,750)
—
92,250
Term Loan Total Liabilities from
Financing Activities
131,802
(5,130)
330
127,002
34,422
—
330
34,752
20. COMMITMENTS AND CONTINGENCIES
COMMITMENTS
The commitments for which the Company is responsible are as follows:
$000s
Firm service transportation
Total
16,871
< 1 year
2,016
1-5 years
11,691
> 5 years
3,164
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.
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
2019
37,815
22,052
10,917
70,784
614
71,398
2018
35,684
23,453
21,186
80,323
393
80,716
Page |48
22. 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
23. 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
Impact of rate change
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, 2019 and 2018 are as follows:
$000s
Exploration and evaluation assets and property, plant and equipment
Share issuance costs
Non capital loss carry-forwards
Unrealized hedging loss
Deferred tax liability
2019
1,646
473
2,119
2019
(42,176)
26.5%
(11,177)
4
108
(94)
9,767
(355)
1,747
—
—%
2019
(7,652)
155
7,267
230
—
2018
1,563
274
1,837
2018
(3,284)
27.0%
(887)
7
156
(95)
—
(1,135)
1,954
—
—%
2018
(12,842)
278
15,138
(2,574)
—
The Company had non-capital losses of approximately $238.5 million (2018 – $217.8 million) which may be applied against future income for Canadian tax
purposes. These non-capital losses expire in 2027 and onwards.
Page |49
CORPORATE INFORMATION
OFFICERS
Neil Korchinski, P. Eng.
President and
Chief Executive Officer
Cheree Stephenson, CA, CPA
Vice President, Finance and
Chief Financial Officer
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 (Syndicate Lead Agent)
Calgary, Alberta
Macquarie Bank Limited
Houston, Texas
TRANSFER AGENT
Odyssey Trust Company
Calgary, Alberta
HEAD OFFICE
2400, 240 – 4th Avenue S.W.
Calgary, Alberta T2P 4H4
Phone: 403-984-9014
Fax: 403-984-2717
WEBSITE
www.petrusresources.com
Page |50