ANNUAL REPORT
2019 Bonterra Energy Corp. is a conventional
oil and gas company with an asset base
comprised of concentrated, stable and
underdeveloped properties located
across western Canada, and is a leading
operator in the light oil Pembina Cardium
reservoir. With a proven track record of
delivering per share growth and creating
long-term value for shareholders, the
Company’s strategy for success is based
on sustainable operations, an experienced
management team, premium assets and
a commitment to maintaining a prudent
capital structure.
TABLE OF CONTENTS
6
7
8
10
11
Annual Highlights
Quarterly Highlights
Report to Shareholders
Commitment to Responsibility
Statistical Review
15 Management’s Discussion and Analysis
30
37
Financial Statements
Notes to the Financial Statements
IBC Corporate Information
Reduction of Net Debt Year-Over-Year
of Funds Flow Generated
Insider Ownership
Common Shares Outstanding
$36.1MILLION$2.88PER SHARE27PERCENT33.4MILLION Bonterra’s assets are concentrated in Alberta’s Pembina and
Willesden Green Cardium fields, among Canada’s largest
oil reservoirs, and are characterized by low-risk drilling
opportunities, stable production rates and high-quality
light oil. We are dedicated to reducing debt and creating
sustainable value for our shareholders by generating
Free Funds Flow. Our low corporate decline rate of
21 percent requires minimal capital to sustain production,
supporting financial flexibility
through a volatile
commodity price environment.
2 Bonterra Energy 2019 Annual Report
Bonterra’sADVANTAGE $96.3MILLION
67PERCENT
Funds Flow Generated in 2019(1)
Oil and Liquids Weighting
The Company generated significant Funds
Flow in 2019, allowing for a fully funded
capital program, payment of a monthly
dividend, and the creation of $36.1 million
in Free Funds Flow(2).
An oil-weighted, low-risk and long-life
asset base, coupled with a low decline rate
that averaged 21 percent in 2019, supports
long-term sustainability.
$53.6
MILLION
Capital Invested in 2019
Bonterra directed $44.5 million to drill
30 gross (23.7 net) new wells, complete and
tie-in 27 gross (20.7 net) wells and allocated
approximately
towards
infrastructure investments.
$9.1 million
(1) Funds Flow is defined as funds provided by operations including proceeds from sale of investments and investment income received excluding the effects of
changes in non-cash working capital items and decommissioning expenditures settled.
(2) Free Funds Flow is defined as Funds Flow less dividends paid to shareholders, capital and decommissioning expenditures settled.
GROWING PROVED RESERVES PER SHARE
WITH CONSERVATIVE CAPITAL EXPENDITURES
2.42
2.44
2.36
2.23
2.17
2.6
2.4
2.2
2.0
1.96
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1.8
2014
2015
2016
2017
2018
2019
Proved reserves per common share
Capital expenditures
$180
$160
$140
$120
$100
$80
$60
$40
$20
$0
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2019 Annual Report Bonterra Energy 3
HIGHLIGHTS
During 2019, Bonterra’s conservative capital expenditures
reflected commodity price volatility and our net debt
reduction focus. With a $53.6 million capital program,
average daily production remained stable at 12,305 BOE
per day. Funds Flow totaled $96.3 million, and
$36.1 million of Free Funds Flow was directed to
reducing net debt by 11 percent year-over-year.
Dividends to shareholders totaled $4.0 million,
achieving a capital plus dividend payout ratio of
60 percent, demonstrating Bonterra’s commitment
to generating returns for shareholders across various
commodity price environments.
4 Bonterra Energy 2019 Annual Report
2019 Bonterra’s focus will remain on generating strong, sustainable Free Funds Flow
which can be used to further reduce debt over the shorter term, pursue growth
opportunities or pay dividends as the balance sheet strengthens over the longer term.
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110
100
90
80
70
60
50
40
30
375
350
325
300
275
250
24
23
22
21
20
19
18
RESERVES GROWTH
99.8
101.2
101.1
94.9
74.3
78.6
10PERCENT
80.6
81.5
Increase in Proved Reserves from 2016 to 2019
Bonterra’s continued ability to generate long-term value and
to bolster its asset base is reflected in the 10 percent increase
in proved reserves, and the seven percent increase in proved
plus probable (“P+P”) reserves since 2016.
2016
2017
2018
2019
Proved
P+P
YEAR END NET DEBT
354.1
328.9
320.0
11PERCENT
Decrease in Net Debt 2019 vs 2018
292.8
Bonterra continues to focus on monitoring overall net
debt while managing Funds Flow and capital expenditures.
The Company intends to further reduce net debt levels,
strengthen the balance sheet and enhance financial flexibility.
2016
2017
2018
2019
P+P RESERVES LIFE INDEX
23.0
23YEARS
2019 Reserve Life Index
21.0
21.0
20.0
Bonterra’s reserve life index, calculated as the P+P reserves
divided by annualized production, increased 10 percent to
23 years in 2019 compared to 21 years in 2018, providing an
extended runway for future development.
2016
2017
2018
2019
2019 Annual Report Bonterra Energy 5
As at and for the year ended ($ 000s except $ per share)
December 31,
2019
December 31,
2018
December 31,
2017
FINANCIAL
Revenue – realized oil and gas sales
Funds Flow(1)
Per share – basic and diluted
Dividend payout ratio
Cash flow from operations
Per share – basic and diluted
Dividend payout ratio
Cash dividends per share
Net earnings
Per share – basic and diluted
Capital expenditures
Disposition
Total assets
Working capital deficiency
Long-term debt
Shareholders' equity
OPERATIONS
Oil
– bbl per day
– average price ($ per bbl)
NGLs
– bbl per day
– average price ($ per bbl)
Natural gas – MCF per day
– average price ($ per MCF)
Total barrels of oil equivalent per day (BOE)(3)
202,749
96,261
2.88
4%
81,132
2.43
5%
0.12
21,923
0.66
53,627
-
223,388
107,251
3.22
34%
202,566
102,444
3.08
39%
115,963
103,873
3.48
32%
1.11
7,167
0.22
78,737
-
3.12
38%
1.20
2,506
0.08
82,441
56,752(2)
1,087,817
1,103,833
1,125,551
19,745
273,065
503,949
7,310
66.34
986
25.83
24,053
1.87
12,305
30,281
298,660
483,970
8,119
65.51
995
40.32
24,549
1.63
13,206
27,790
292,212
510,260
7,907
59.30
905
31.47
24,087
2.40
12,827
(1) Funds Flow is not a recognized measure under IFRS. For these purposes, the Company defines Funds Flow as funds provided by operations including proceeds
from sale of investments and investment income received excluding the effects of changes in non-cash working capital items and decommissioning expenditures
settled.
(2) For 2017, includes the disposition of a two percent overriding royalty interest on the total production from the Company’s Pembina Cardium pool that closed
December 20, 2017 and was effective January 1, 2018. Consideration consisted of $52 million of cash and incremental Cardium assets valued at $4.7 million which
is included in capital expenditures (refer to Note 5 of the December 31, 2017 audited annual financial statements).
(3) BOE may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 MCF: 1 bbl is based on an energy conversion method primarily applicable
at the burner tip and does not represent a value equivalency at the wellhead.
6 Bonterra Energy 2019 Annual Report
AnnualHIGHLIGHTS
As at and for the periods ended ($ 000s except $ per share)
Q4
2019
Q3
Q2
Q1
FINANCIAL
Revenue – oil and gas sales
Funds Flow(1)
Per share – basic and diluted
Dividend payout ratio
Cash flow from operations
Per share – basic and diluted
Dividend payout ratio
Cash dividends per share
Net earnings (loss)
Per share – basic and diluted
Capital expenditures
Total assets
Working capital deficiency
Long-term debt
Shareholders' equity
OPERATIONS
Oil (barrels per day)
Average price ($ per bbl)
NGLs (barrels per day)
Average price ($ per bbl)
Natural gas (MCF per day)
Average price ($ per MCF)
Total BOE per day(2)
50,743
23,055
0.69
4%
20,767
0.62
5%
0.03
(1,389)
(0.04)
5,678
47,320
22,596
0.68
4%
19,774
0.59
5%
0.03
(1,276)
(0.04)
17,845
54,852
26,247
0.79
4%
25,468
0.76
4%
0.03
23,131
0.69
9,042
49,834
24,363
0.73
4%
15,123
0.45
7%
0.03
1,457
0.04
21,062
1,087,817
1,133,137
1,123,513
1,124,043
19,745
273,065
503,949
7,255
63.37
1,016
24.39
24,697
2.71
12,387
24,599
283,470
506,011
7,157
65.49
1,009
22.45
23,820
0.96
12,136
22,238
288,545
507,659
7,746
71.27
970
25.53
23,750
1.09
12,674
30,139
296,594
484,980
7,081
64.87
949
31.40
23,938
2.70
12,020
(1) Funds Flow is not a recognized measure under IFRS. For these purposes, the Company defines Funds Flow as funds provided by operations including
proceeds from sale of investments and investment income received excluding the effects of changes in non-cash working capital items and decommissioning
expenditures settled.
(2) BOE may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 MCF: 1 bbl is based on an energy conversion method primarily applicable
at the burner tip and does not represent a value equivalency at the wellhead.
2019 Annual Report Bonterra Energy 7
QuarterlyHIGHLIGHTS
Bonterra Energy Corp. (“Bonterra” or the “Company”) has
faced unprecedented challenges impacting the Canadian
energy industry through 2019 and into 2020 including
extreme commodity price volatility, global oil supply and
demand imbalances caused by price wars, pipeline capacity
constraints, adjustments to regulatory policy and the recent
impact of COVID-19 (Coronavirus) which have combined
to create an increasingly difficult environment for oil and
gas producers. This backdrop highlights the importance
of Bonterra’s commitment to maintaining or reducing debt
levels, executing a defensive capital program and seeking
to conservatively manage its assets to support long-term
shareholder value creation.
8 Bonterra Energy 2019 Annual Report
Report toSHAREHOLDERS Bonterra 2019 Highlights
• Averaged 12,305 BOE per day of production in 2019 and
12,387 BOE per day for the final three months of the year,
reflecting modest capital spending in 2019 coupled with
approximately 350 BOE per day of shut-in production volumes
related to facility maintenance and low natural gas prices.
• Generated Funds Flow of $96.3 million ($2.88 per share) in
2019 which supported continued funding of Bonterra’s capital
program, monthly dividend and debt repayment.
• Invested approximately $53.6 million in capital expenditures for
the year ended December 31, 2019, with $44.5 million directed
to drilling 30 gross (23.7 net) wells with a 100 percent success
rate, and completing and tying in 27 gross (20.7 net) wells,
with the remaining three gross (3.0 net) wells commencing
production in early Q1 2020; the additional $9.1 million was
directed to infrastructure investments.
• Reduced net debt by 11 percent to $292.8 million compared
to $328.9 million at December 31, 2018, improving Bonterra’s
financial flexibility and enhancing long-term sustainability.
• Recorded Free Funds Flow of $36.1 million which was allocated
to meaningful reductions in net debt.
• Total proved reserves per fully diluted share totaled 2.44 BOE, a
1.0 percent increase over 2.42 BOE in 2018, while P+P reserves
per fully diluted share totaled 3.03 BOE compared to 3.04 BOE
per share in 2018.
Bonterra’s Advantages
Bonterra continues to focus on the prudent development of our
high-quality, light sweet oil-weighted asset base, and to take
a conservative approach to capital allocation, allowing for
flexibility in response to extreme variability of global commodity
markets. Balance sheet strength and the protection of value in
this environment remain top priorities in the near term, with an
focus on responding strategically to commodity
ongoing
price instability.
Cost control has always been a hallmark of Bonterra’s operations,
and this focus will continue through 2020 and beyond. By owning
the majority of its facilities and gas plants, Bonterra can maintain
better control of its cost structure through the processing of its oil,
natural gas liquids and natural gas. Bonterra operates 90 percent
of its production with an average working interest of 76 percent
and operates most of the related oil and gas processing
facilities, which require minimal additional capital to increase
throughput. At approximately 21 percent, the Company has one
of the lowest decline rates among its peer group, which
low maintenance capital requirements and
contributes to
supports long-term sustainability.
Outlook
The global events mentioned above have reinforced the
importance of maintaining an adaptable capital strategy and
taking a defensive position to protect the organization amidst
severe uncertainty. Consistent with this strategy, the Company
has taken several steps to ensure strength and resiliency during
this period. Bonterra has committed to spending capital of
approximately $25 million and will defer any additional drilling or
completions capital investment until pricing is more supportive.
Further, the Company has actively assessed areas and infrastructure
that are uneconomic in the current environment and has shut-in
production volumes to protect corporate returns. Lastly, the
Company’s Board of Directors elected to suspend its monthly
dividend, commencing in April, until the economic environment
can support a sustained dividend payment. Along with our
commitment to Environmental, Social, and Governance principles,
Bonterra’s strategy is designed to withstand volatile commodity
prices and a highly uncertain outlook.
To further mitigate the continued commodity price volatility
and support added stability, the Company has entered into
physical delivery sales and risk management contracts to realize
average Edmonton Par prices on crude oil between C$59.08 and
C$69.60 per bbl on 2,000 barrels per day of production for January
to February, 2,500 barrels per day for March and 2,000 barrels
per day for the second quarter of 2020. The Company will continue
to pursue additional opportunities to enhance funds flow and
financial flexibility.
The Board of directors and management of the Company wish
to thank all shareholders for their continued trust through a
notably difficult operating environment, and to all employees and
consultants for their invaluable contributions.
George F. Fink
Chief Executive Officer and Chairman of the Board
2019 Annual Report Bonterra Energy 9
Bonterra recognizes the important role we play as an employer,
corporate citizen and participant in the local community. We hold
ourselves to the highest standards of corporate responsibility,
and approach business in a way that fosters responsible oil and
gas development.
Bonterra recognizes that corporate responsibility does not end
at the operational level; in reality, it extends to our community
and beyond. As a Company, community means more than just the
location in which we conduct business.
the
to support
We endeavour
individuals, groups, and
municipalities in and around the locations where we operate
through equal opportunity and we prioritize the employment
of
local businesses and community members to conduct
our operations.
Health, Safety and Environment (HS&E)
Bonterra is committed to meet or exceed all relevant industry
HS&E regulations and standards. We accomplish our HS&E goals
by implementing a program, applicable to all of Bonterra’s
operations and employees, that considers a broad range of
stakeholders and workplace environments. Our HS&E practices
underscore the following priorities:
• Employing minimal disturbance techniques to reduce the
overall impact to the environment caused by our operations;
• Ensure
all
employees,
and Company
representatives are provided with applicable health, safety,
security and environmental and regulatory training;
contractors,
• Secure a safe work environment with robust policies, procedures,
equipment and emergency response plans;
• Provide timely and effective response to any incidents that
may occur, enabling rapid recoveries and conducting thorough
incident investigations;
• Employ vigorous asset integrity programs to ensure the safe
operation of pipelines and associated facilities; and
• Consult internal and external stakeholders that are impacted by
our operations, and remain committed to working with involved
parties to resolve any concerns or questions that may arise.
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10 Bonterra Energy 2019 Annual Report
CommitmentTO RESPONSIBILITY
Summary of Gross Oil and Gas Reserves as of December 31, 2019
Reserves Category
PROVED
Developed Producing
Developed Non-producing
Undeveloped
TOTAL PROVED
PROBABLE
TOTAL PROVED PLUS PROBABLE(1)(2)(3)
Light &
Medium
Crude Oil
Conventional
Natural Gas
(Mbbl)
(MMcf)
Natural Gas
Liquids
(Mbbl)
Oil
Equivalent(4)
Future
Development
Capital
(MBoe)
($ 000s)
22,227
591
23,891
46,709
11,165
57,874
75,544
1,219
85,582
162,345
38,981
201,326
3,319
55
4,398
7,771
1,878
9,649
38,136
849
42,552
81,537
19,540
101,077
76
1,374
638,193
639,643
12,006
651,650
(1) Reserves have been presented on gross basis which are the Company’s total working interest share before the deduction of any royalties and without including
any royalty interests of the Company.
(2) Totals may not add due to rounding.
(3) Based on Sproule’s December 31, 2019 escalated price deck.
(4) Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil.
Reconciliation of Company Gross Reserves by Principal Product Type
as of December 31, 2019(1)(2)
Light &
Medium Crude Oil
Proved
(Mbbl)
Proved +
Probable
(Mbbl)
Conventional Natural Gas
Natural Gas
Liquids
Total
Proved
(MMcf)
Proved +
Probable
(MMcf)
Proved
(Mbbl)
Proved +
Probable
(Mbbl)
Proved
(MBoe)
Proved +
Probable
(MBoe)
47,885
60,067
153,973
193,380
7,086
8,928
80,634
101,225
2,551
(375)
3,154
(2,034)
9,348
8,517
11,543
5,825
-
-
-
-
-
-
-
-
-
-
-
-
(685)
(2,668)
(645)
(2,668)
(714)
(8,779)
(643)
(8,779)
664
481
-
-
-
(100)
(360)
817
365
-
-
-
(101)
(360)
4,773
1,525
-
-
-
5,894
(698)
-
-
-
(904)
(4,491)
(853)
(4,491)
46,709
57,874
162,345
201,326
7,771
9,649
81,537
101,077
Opening Balance,
December 31, 2018
Extensions & Improved
Recovery(2)
Technical Revisions
Discoveries
Acquisitions
Dispositions(3)
Economic Factors
Production
CLOSING BALANCE,
DECEMBER 31, 2019(4)
(1) Gross Reserves means the Company’s working interest reserves before calculation of royalties, and before consideration of the Company’s royalty interests.
(2)
Increases to Extensions & Improved Recovery include infill drilling and are the result of step-out locations drilled by Bonterra and other operators on and near
Company-owned lands.
(3)
Includes volumes associated with Farm outs.
(4) Totals may not add due to rounding.
2019 Annual Report Bonterra Energy 11
StatisticalREVIEW
Summary of Net Present Values of Future Net Revenue as of December 31, 2019
($ 000s)
Reserves Category
PROVED
Developed Producing
Developed Non-producing
Undeveloped
TOTAL PROVED
PROBABLE
TOTAL PROVED + PROBABLE(1)(2)(3)(4)
Net Present Value Before Income Taxes Discounted at (% per Year)
0%
5%
10%
15%
789,954
17,432
981,038
1,788,424
731,254
2,519,678
727,746
13,466
578,193
1,319,405
402,609
1,722,014
586,445
10,627
364,808
961,880
266,354
1,228,235
485,957
8,593
241,291
735,842
196,077
931,919
(1) Evaluated by Sproule as at December 31, 2019. Net present value of future net revenue does not represent fair value of the reserves.
(2) Net present values equal net present value before income taxes based on Sproule’s forecast prices and costs as of December 31, 2019. There is no assurance
that the forecast prices and cost assumptions will be attained and variances could be material.
(3)
Includes abandonment and reclamation costs as defined in NI 51-101.
(4) Total may not add due to rounding.
Finding, Development & Acquisition (FD&A) and Finding & Development (F&D) Costs
Proved Reserves Net Additions
Proved + Probable Reserves Net Additions
2019
2018
2017
3 Yr Avg(4)
2019
2018
2017
3 Yr Avg(4)
FD&A COSTS PER BOE(1)(2)(3)
Including FDC
Excluding FDC
F&D COSTS PER BOE(1)(2)(3)
Including FDC
Excluding FDC
$
$
$
$
14.32 $
12.82
$
15.66
$
9.94 $
11.40 $
9.06 $
14.32 $
12.99 $
16.93 $
9.94 $
12.54 $
9.46 $
14.41
10.04
14.98
10.55
$
$
$
$
18.24 $
14.33 $
13.74 $
12.35 $
12.70 $
8.57 $
18.24 $
15.56 $
15.13 $
12.35 $
14.95 $
9.16 $
14.89
10.65
16.02
11.59
(1)
(2)
Barrels of Oil Equivalent may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 MCF: 1 bbl is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future
development costs generally will not reflect total finding and development costs related to reserve additions for that year.
(3)
FD&A and F&D costs are net of proceeds of disposal and the FD&A costs per BOE are based on reserves acquired net of reserves disposed of.
(4)
Three-year average is calculated using three-year total capital costs and reserve additions on both Proved and Proved + Probable reserves on a weighted
average basis.
12 Bonterra Energy 2019 Annual Report
Commodity Prices Used in the Above Calculations of Reserves are as Follows:
Year
FORECAST
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
Edmonton
Par Price
($Cdn per bbl)
Natural Gas
AECO-C Spot
($Cdn per Mmbtu)
Butanes
Edmonton
($Cdn per bbl)
Pentanes
Edmonton
($Cdn per bbl)
Operating Cost
Inflation Rate
(% per Year)
Exchange
Rate
($US/$Cdn)
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
37.72
43.90
47.74
48.69
49.67
50.66
51.67
52.71
53.76
54.84
55.93
76.32
80.52
80.00
81.68
83.38
85.13
86.90
88.72
90.57
92.45
94.38
0.0
1.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
0.76
0.77
0.80
0.80
0.80
0.80
0.80
0.80
0.80
0.80
0.80
Crude oil, natural gas and liquid prices escalate at 2.0 percent thereafter.
Production
Alberta
Saskatchewan
British Columbia
Land Holdings
Alberta
Saskatchewan
British Columbia
2019
Conventional
Natural Gas
(MCF per day)
Total
(BOE per day)
23,227
12,026
40
786
143
136
24,053
12,305
Oil & NGLs
(bbl per day)
8,155
136
5
8,296
2019
2018
Gross Acres
Net Acres
Gross Acres
Net Acres
331,566
8,637
62,045
402,248
203,191
5,680
23,690
232,561
339,019
8,178
62,045
409,242
208,086
5,691
23,478
237,255
2019 Annual Report Bonterra Energy 13
Petroleum and Natural Gas Expenditures
The following table summarizes petroleum and natural gas capital expenditures incurred by Bonterra on acquisisitons, land, and
exploration and development costs for the years ended December 31:
($ 000s)
Land
Acquisitions
Disposals
Exploration and development costs
Net petroleum and natural gas capital expenditures
Drilling History
The following tables summarize Bonterra’s gross and net drilling activity and success:
2019
-
-
-
53,627
53,627
Crude oil
Natural gas
Total
Success rate
Crude oil
Natural gas
Total
Success rate
Development
Gross
30.0
-
30.0
100%
Net
23.7
-
23.7
100%
2019
Exploratory
Gross
Net
-
-
-
-
-
-
-
-
Development
2018
Exploratory
Total
Gross
30.0
-
30.0
100%
Total
Gross
Net
Gross
Net
Gross
Net
34.0
28.0
-
-
34.0
28.0
-
-
-
-
-
-
34.0
28.0
-
-
34.0
100%
100%
-
-
100%
28.0
100%
2018
535
3,125
-
75,077
78,737
Net
23.7
-
23.7
100%
14 Bonterra Energy 2019 Annual Report
Management’s Discussion and Analysis
The following report dated March 10, 2020 is a review of the operations and current financial position for the year ended
December 31, 2019 for Bonterra Energy Corp. (“Bonterra” or “the Company”) and should be read in conjunction with the audited
financial statements presented under International Financial Reporting Standards (IFRS), including the notes related thereto.
Use of Non-IFRS Financial Measures
Throughout this Management’s Discussion and Analysis (MD&A) the Company uses the terms “payout ratio”, “cash netback” and “net
debt” to analyze operating performance, which are not standardized measures recognized under IFRS and do not have a standardized
meaning prescribed by IFRS. These measures are commonly used in the oil and gas industry and are considered informative by
management, shareholders and analysts. These measures may differ from those made by other companies and accordingly may not be
comparable to such measures as reported by other companies.
The Company calculates payout ratio percentage by dividing cash dividends paid to shareholders by cash flow from operating
activities, both of which are measures prescribed by IFRS which appear on our statement of cash flows. We calculate cash netback by
dividing various financial statement items as determined by IFRS by total production for the period on a barrel of oil equivalent basis.
The Company calculates net debt as long-term debt plus working capital deficiency (current liabilities less current assets).
Frequently Recurring Terms
Bonterra uses the following frequently recurring terms in this MD&A: “WTI” refers to West Texas Intermediate, a grade of light sweet
crude oil used as benchmark pricing in the United States; “MSW Stream Index” or “Edmonton Par” refers to the mixed sweet blend
that is the benchmark price for conventionally produced light sweet crude oil in Western Canada; “AECO” refers to Alberta Energy
Company, a grade or heating content of natural gas used as benchmark pricing in Alberta, Canada; “bbl” refers to barrel; “NGL” refers
to Natural gas liquids; “MCF” refers to thousand cubic feet; “MMBTU” refers to million British Thermal Units; “GJ” refers to gigajoule;
and “BOE” refers to barrels of oil equivalent. Disclosure provided herein in respect of a BOE may be misleading, particularly if used in
isolation. A BOE conversion ratio of 6 MCF: 1 bbl is based on an energy conversion method primarily applicable at the burner tip and
does not represent a value equivalency at the wellhead.
Numerical Amounts
The reporting and the functional currency of the Company is the Canadian dollar.
15 Bonterra Energy 2019 Annual Report
2019 Annual Report Bonterra Energy 15
Annual Comparisons
As at and for the year ended ($ 000s except $ per share)
December 31,
2019
December 31,
2018
December 31,
2017
FINANCIAL
Revenue – realized oil and gas sales
Cash flow from operations
Per share – basic and diluted
Payout ratio
Cash dividends per share
Net earnings
Per share – basic and diluted
Capital expenditures, net of disposition
Disposition
Total assets
Working capital deficiency
Long-term debt
Shareholders' equity
OPERATIONS
Oil
– bbl per day
– average price ($ per bbl)
NGLs
– bbl per day
– average price ($ per bbl)
Natural gas – MCF per day
– average price ($ per MCF)
Total barrels of oil equivalent per day (BOE)
202,749
81,132
2.43
5%
0.12
21,923
0.66
53,627
-
223,388
115,963
3.48
32%
1.11
7,167
0.22
78,737
-
202,566
103,873
3.12
38%
1.20
2,506
0.08
82,441
56,752(1)
1,087,817
1,103,833
1,125,551
19,745
273,065
503,949
7,310
66.34
986
25.83
24,053
1.87
12,305
30,281
298,660
483,970
8,119
65.51
995
40.32
24,549
1.63
13,206
27,790
292,212
510,260
7,907
59.30
905
31.47
24,087
2.40
12,827
(1) For Q4 2017, includes the disposition of a two percent overriding royalty interest on the total production from the Company’s Pembina Cardium pool that closed
December 20, 2017 and was effective January 1, 2018. Consideration consisted of $52 million of cash and incremental Cardium assets valued at $4.7 million which
is included in capital expenditures (refer to Note 5 of the December 31, 2017 audited annual financial statements).
16 Bonterra Energy 2019 Annual Report
2019 Annual Report Bonterra Energy 16
Quarterly Comparisons
As at and for the periods ended ($ 000s except $ per share)
Q4
2019
Q3
Q2
Q1
FINANCIAL
Revenue – oil and gas sales
Cash flow from operations
Per share – basic and diluted
Dividend payout ratio
Cash dividends per share
Net earnings (loss)
Per share – basic and diluted
Capital expenditures
Total assets
Working capital deficiency
Long-term debt
Shareholders' equity
OPERATIONS
Oil (bbl per day)
NGLs (bbl per day)
Natural gas (MCF per day)
Total BOE per day
50,743
20,767
0.62
5%
0.03
(1,389)
(0.04)
5,678
47,320
19,774
0.59
5%
0.03
(1,276)
(0.04)
17,845
54,852
25,468
0.76
4%
0.03
23,131
0.69
9,042
49,834
15,123
0.45
7%
0.03
1,457
0.04
21,062
1,087,817
1,133,137
1,123,513
1,124,043
19,745
273,065
503,949
7,255
1,016
24,697
12,387
24,599
283,470
506,011
7,157
1,009
23,820
12,136
22,238
288,545
507,659
7,746
970
23,750
12,674
30,139
296,594
484,980
7,081
949
23,938
12,020
2018
Q3
Q2
Q1
As at and for the periods ended ($ 000s except $ per share)
Q4
FINANCIAL
Revenue – oil and gas sales
Cash flow from operations
Per share – basic and diluted
Dividend payout ratio
Cash dividends per share
Net earnings (loss)
Per share – basic and diluted
Capital expenditures
Total assets
Working capital deficiency
Long-term debt
Shareholders' equity
OPERATIONS
Oil (bbl per day)
NGLs (bbl per day)
Natural gas (MCF per day)
Total BOE per day
34,988
20,509
0.61
34%
0.21
(10,909)
(0.33)
4,785
1,103,833
30,281
298,660
483,970
7,756
1,025
24,045
12,789
63,817
33,669
1.01
30%
0.30
5,756
0.17
18,814
1,137,748
35,319
293,197
500,507
7,949
1,070
24,144
13,043
67,458
31,908
0.96
31%
0.30
8,925
0.27
18,970
1,147,501
27,069
303,413
503,979
8,743
984
25,317
13,946
57,124
29,877
0.90
33%
0.30
3,395
0.10
36,168
1,142,670
46,630
291,994
504,240
8,034
900
24,701
13,051
2019 Annual Report Bonterra Energy 17
Business Environment and Sensitivities
Bonterra’s financial results are significantly influenced by fluctuations in commodity prices, including price differentials, as well as
production volumes and foreign exchange rates. The following table depicts selective market benchmark commodity prices, differentials
and foreign exchange rates in the last eight quarters to assist in understanding how past volatility has impacted Bonterra’s financial
and operating performance. The increases or decreases in Bonterra’s realized average price for oil and natural gas for each of the eight
quarters is also outlined in detail in the following table.
Crude oil
WTI (US$/bbl)
WTI to MSW Stream Index
Differential (US$/bbl)(1)
Foreign exchange
US$ to Cdn$
Bonterra average realized
oil price (Cdn$/bbl)
Natural gas
AECO (Cdn$/mcf)
Bonterra average realized
gas price (Cdn$/mcf)
Q4-2019
Q3-2019
Q2-2019
Q1-2019
Q4-2018
Q3-2018
Q2-2018
Q1-2018
56.96
56.45
59.81
54.90
58.81
69.50
67.88
62.87
(5.37)
(4.66)
(4.62)
(4.85)
(26.30)
(6.83)
(5.45)
(5.89)
1.3201
1.3207
1.3375
1.3293
1.3215
1.3070
1.2911
1.2651
63.37
65.49
71.27
64.87
38.96
77.20
76.51
67.78
2.46
2.71
0.91
0.96
1.03
1.09
2.61
2.70
1.55
1.77
1.19
1.37
1.18
1.16
2.07
2.24
(1) This differential accounts for the majority of the difference between WTI and Bonterra’s average realized price (before quality adjustments and foreign exchange).
The overall volatility in Bonterra’s average realized commodity prices can be impacted by numerous events or factors, including but not
limited to:
• Worldwide (particularly North American) crude oil supply and demand imbalance;
• Geo-political events that affect worldwide crude oil supply and demand;
• The value of the Canadian dollar compared to the US dollar;
• Access to infrastructure and markets;
• Crude oil curtailments;
• Weather; and
• Timing and duration of plant, refinery and pipeline maintenance.
Volatility in WTI benchmark pricing continued through the fourth quarter of 2019 as uncertainties around global supply and demand
persist, along with heightened geopolitical concerns that began earlier in the year with an attack on Saudi Arabia’s largest crude
processing facility. Concern regarding global demand imbalances in the second half of 2019 and into 2020 comes from a variety of
factors, including but not limited to global trade disputes between the US and China and the impact of the Coronavirus epidemic.
There is further uncertainty around crude oil supply growth, including continued shale oil development in the US, the impact of which
was exacerbated in early March 2020 due to Russia’s departure from OPEC+ and Saudi Arabia’s stated objective to ramp up production
and cause an oil price war. The impact of such competition for market share could have a significant, sustained negative effect on global
commodity prices. In Canada, volatility subsided somewhat through 2019 as crude curtailments mandated by the Alberta Government,
along with incremental rail and seasonal factors, resulted in a decrease in crude inventories and a narrowing of the differential for all
grades of Canadian crude. While the curtailment program has reduced Canadian crude price volatility, it has not negated the need
for incremental pipeline capacity out of the country. Looking forward, completion of any proposed pipeline expansion projects or
increasing Canada’s export capabilities by expanding capacity on existing lines will have a positive effect on the movement and pricing
of Canadian barrels.
The AECO benchmark price for natural gas improved into the fourth quarter of 2019 with the onset of winter and the associated increase
in heating demand. Looking forward, the implementation of a Temporary Service Protocol to manage supply during maintenance
periods on TC Energy’s NGTL pipeline system is expected to result in more stable pricing through 2020. Beyond 2020, planned facility
additions for the NGTL gas transmission system and a positive final investment decision by LNG Canada may improve sentiment
towards western Canadian-based natural gas producers. While these projects do not impact near-term supply and demand imbalances,
they do have positive implications for the longer term.
18 Bonterra Energy 2019 Annual Report
The following chart shows the Company’s sensitivity to key commodity price variables. The sensitivity calculations are performed
independently and show the effect of changing one variable while holding all other variables constant.
Annualized sensitivity analysis on cash flow, as estimated for 2019(1)
Impact on cash flow
Realized crude oil price ($/bbl)
Realized natural gas price ($/mcf)
U.S.$ to Canadian $ exchange rate
Change ($)
1.00
0.10
0.01
$ 000s
2,808
1,016
1,517
$ per share(2)
0.08
0.03
0.05
(1) This analysis uses current royalty rates, annualized estimated average production of 12,500 BOE per day and no changes in working capital.
(2) Based on annualized basic weighted average shares outstanding of 33,388,796.
Business Overview, Strategy and Key Performance Drivers
Bonterra is an upstream oil and gas company that is primarily focused on the development of its Cardium land within the Pembina and
Willesden Green areas located in central Alberta. The Pembina Cardium reservoir is the largest conventional oil reservoir in western
Canada that features large original oil in place with very low recoveries to date. Bonterra operates approximately 90 percent of its
production and operates the majority of its related oil and gas processing facilities, which require minimal additional capital to support
an increase of production. At December 31, 2019, Bonterra has identified a horizontal drilling inventory of approximately 700 net
locations (for more information and advisories regarding drilling locations, please refer to Drilling Locations within the Forward Looking
Information section). Bonterra has also identified additional drilling locations in other formations within Alberta, Saskatchewan and
British Columbia.
Bonterra continues to remain focused on long-term sustainability and improving its balance sheet through debt reduction. During 2019,
Bonterra generated cash flow in excess of capital and dividends and reduced net debt by $36.1 million, having closed the year with
net debt of $292.8 million, an 11 percent decrease from $328.9 million at December 31, 2018. The Company managed this net debt
reduction with reduced capital spending offset by increased production costs from an increased number of required multi-year facility
turnarounds in 2019 compared to prior years. With the expected decrease in facility maintenance costs, Bonterra will continue to pursue
balance sheet strength and enhanced financial flexibility through 2020. Cash flow after capital and the amount of dividend outlays
continues to be prioritized for the enhancement of debt ratios.
During 2019, Bonterra invested $53.6 million in capital, directing approximately $44.5 million to drill 30 gross (23.7 net) wells,
complete and tie-in 27 gross (20.7 net) wells, with the remaining three wells brought on production in Q1 2020. In addition, approximately
$9.1 million was directed to infrastructure investments, and Bonterra maintained average annual daily production of 12,305 BOE
per day. Production was two percent lower than the low end of 2019 guidance disclosed at Q3 2019 of 12,600 BOE per day to
13,200 BOE per day, reflecting approximately 350 BOE per day of production being shut-in through the year related to facility
maintenance and low natural gas prices. The Company returned approximately $4 million to shareholders in the form of dividends.
Bonterra’s all-in payout ratio was 71 percent in 2019, calculated by combining the total dividend amount with capital expenditures and
dividing by cash flow from operations.
In response to severe market volatility, and as part of Bonterra’s ongoing efforts to diversify crude oil pricing and to protect future
cash flow, the Company entered into physical delivery sales and risk management contracts for the first half of 2020. During 2020, the
Company will receive fixed Edmonton Par prices on 2,000 bbls per day of crude oil in Q1 2020 between $64.46 CAD to $69.60 CAD
per bbl and on 2,000 bbls per day of crude oil in Q2 2020 between $59.50 CAD to $70.25 CAD per bbl, with an additional
500 bbls per day of crude oil for the month of March 2020 at $59.08 CAD per bbl. The Company also diversified its natural gas
pricing for the warmer months of 2020 by entering into a physical delivery sales contracts for 5,000 GJs per day from April 1, 2020 to
October 31, 2020 ranging between $1.55 CAD to $1.64 CAD per GJ.
As a result of unprecedented volatility in global commodity markets, the Company will continue to prioritize balance sheet strength,
preserve the inherent value of assets, and retain flexibility with its capital program to rapidly respond to fluctuations in the broader
commodity price environment. Consistent with this strategy, the Company has taken several steps to ensure strength and resiliency
during this period. While the previously announced 2020 capital budget of $70 million is under review, approximately $25 million of
spending is committed to date. Bonterra will defer any additional drilling or completions capital investment until economic conditions
are more supportive. Further, the Company is actively assessing areas and infrastructure that are uneconomic in the current environment
and has shut-in production volumes to protect corporate returns. Lastly, the Company’s Board of Directors has elected to suspend its
monthly dividend, commencing in April, until the economic environment can support a sustained dividend payment. Bonterra may
elect to adjust the amount and timing of capital spending to ensure optimal returns while seeking to further reduce its debt levels.
A commitment to sustainability and debt reduction will remain intact through 2020.
Bonterra’s successful operations are dependent upon several factors including, but not limited to: commodity prices, efficient
management of capital spending, the amount of monthly dividends, the ability to maintain desired levels of production, control over
infrastructure, efficiency in developing and operating properties, and the ability to control costs. The Company’s key measures of
2019 Annual Report Bonterra Energy 19
performance with respect to these drivers include but are not limited to: average daily production volumes, average realized prices,
and average operating costs per unit of production. Disclosure of these key performance measures can be found in this MD&A and/or
previous interim or annual MD&A disclosures.
Drilling
Three months ended
Year ended
December 31,
2019
September 30,
2019
December 31,
2018
December 31,
2019
December 31,
2018
Gross(1)
Net(2) Gross(1)
Net(2) Gross(1)
Net(2) Gross(1)
Net(2) Gross(1)
Net(2)
Crude oil horizontal-operated
Crude oil horizontal-non-operated
Total
Success rate
3
1
4
3.0
0.1
3.1
100%
7
5
12
7.0
0.5
7.5
100%
0
2
2
0.0
0.3
0.3
100%
23
7
30
23.0
0.7
23.7
100%
27
7
34
26.9
1.1
28.0
100%
(1) “Gross” wells are the number of wells in which Bonterra has a working interest.
(2) “Net” wells are the aggregate number of wells obtained by multiplying each gross well by Bonterra’s percentage of working interest.
During 2019, the Company drilled 23 gross (23.0 net) operated wells and completed 20 gross (20.0 net) operated wells, of which
20 gross (20.0 net) wells were tied-in and placed on production. The remaining three gross (3.0 net) wells commenced production in
early Q1 2020.
In addition, seven gross (0.7 net) non-operated wells were drilled, completed, equipped and placed on production in 2019.
Production
Crude oil (bbl per day)
NGLs (bbl per day)
Natural gas (MCF per day)
Average BOE per day
Three months ended
Year ended
December 31,
2019
September 30,
2019
December 31,
2018
December 31,
2019
December 31,
2018
7,255
1,016
24,697
12,387
7,157
1,009
23,820
12,136
7,756
1,025
24,045
12,789
7,310
986
24,053
12,305
8,119
995
24,549
13,206
Annual production averaged 12,305 BOE per day in 2019, compared to 13,206 BOE per day for the same period in 2018, reflecting
significantly lower capital spending in 2019 compared to 2018, which led to fewer new wells coming on production. In addition, during
2019 an average of approximately 350 BOE per day of production was shut-in primarily due to facility turnarounds being undertaken
on a large number of gas plants and batteries, as well as the voluntary shut-in of British Columbia (“BC”) natural gas wells due to low
realized natural gas prices. The BC natural gas wells were placed back on production as gas prices increased in the fourth quarter.
Fourth quarter 2019 production was higher than the previous quarter due to the timing of new wells being brought onto production and
the reactivation of the BC natural gas wells in November of 2019.
Cash Netback
The following table illustrates the calculation of the Company’s cash netback from operations for the periods ended:
$ per BOE
Production volumes (BOE)
Gross production revenue
Royalties
Production costs
Field netback
General and administrative
Interest and other
Cash netback
Three months ended
Year ended
December 31,
2019
September 30,
2019
December 31,
2018
December 31,
2019
December 31,
2018
1,139,615
1,116,506
1,176,545
4,491,303
4,820,186
44.53
(2.24)
(16.94)
25.35
(1.68)
(3.05)
20.62
42.38
(3.76)
(14.32)
24.30
(1.05)
(3.35)
19.90
29.74
(3.17)
(14.23)
12.34
(1.19)
(3.08)
8.07
45.14
(3.18)
(15.51)
26.45
(1.53)
(3.37)
21.55
46.34
(4.94)
(14.49)
26.91
(1.51)
(3.16)
22.24
20 Bonterra Energy 2019 Annual Report
Cash netbacks decreased in 2019 compared to 2018 primarily due to lower realized commodity prices and increased production costs
per BOE, which were partially offset by a decrease in royalties per BOE.
Cash netbacks for Q4 2019 increased compared to Q3 2019 due to higher realized commodity prices and an adjustment on past crown
royalties paid, which were partially offset by higher production costs per BOE.
Oil and Gas Sales
Revenue – oil and gas sales ($ 000s)
Crude oil
NGL
Natural gas
Average realized prices:
Crude oil ($ per barrel)
NGLs ($ per barrel)
Natural gas ($ per MCF)
Average ($ per BOE)
Average BOE per day
Three months ended
Year ended
December 31,
2019
September 30,
2019
December 31,
2018
December 31,
2019
December 31,
2018
42,297
2,280
6,166
50,743
63.37
24.39
2.71
44.53
12,387
43,121
2,085
2,114
47,320
65.49
22.45
0.96
42.38
12,136
27,801
3,273
3,914
34,988
38.96
34.73
1.77
29.74
12,789
176,996
9,300
16,453
202,749
66.34
25.83
1.87
45.14
12,305
194,137
14,645
14,606
223,388
65.51
40.32
1.63
46.34
13,206
Revenue from oil and gas sales in 2019 decreased by $20,639,000, or nine percent, compared to the same period in 2018. The decrease
in oil and gas sales was primarily driven by a seven percent decrease in production volumes and a decrease in commodity prices for
oil and NGLs. The quarter-over-quarter increase in oil and gas sales was primarily due to an increase in both production volumes and
natural gas prices compared to Q3 2019.
The Company’s product split on a revenue basis is weighted approximately 92 percent to crude oil and NGLs for 2019.
Royalties
($ 000s)
Crown royalties
Freehold, gross overriding and
other royalties
Total royalties
Crown royalties – percentage of revenue
Freehold, gross overriding and other
royalties – percentage of revenue
Royalties – percentage of revenue
Royalties $ per BOE
Three months ended
Year ended
December 31,
2019
September 30,
2019
December 31,
2018
December 31,
2019
December 31,
2018
780
1,770
2,550
1.5
3.5
5.0
2.24
2,563
1,632
4,195
5.4
3.4
8.8
3.76
2,476
1,254
3,730
7.1
3.6
10.7
3.17
7,230
7,044
14,274
3.6
3.5
7.1
3.18
15,157
8,665
23,822
6.8
3.9
10.7
4.94
Royalties paid by the Company consist of both crown royalties to the Provinces of Alberta, Saskatchewan and British Columbia and
other royalties. Total royalties for the year ended December 31, 2019 decreased by $1.76 per BOE compared to 2018. The decrease is
primarily the result of a crown royalty refund of $2.1 million and lower commodity prices in 2019 than the prior year. The crown royalty
refund recorded in the fourth quarter of 2019 was due to a reassessment on past royalties paid.
Production Costs
($ 000s except $ per BOE)
Production costs
$ per BOE
Three months ended
Year ended
December 31,
2019
September 30,
2019
December 31,
2018
December 31,
2019
December 31,
2018
19,304
16.94
15,989
14.32
16,746
14.23
69,673
15.51
69,861
14.49
2019 Annual Report Bonterra Energy 21
Production costs for 2019 did not substantially change from 2018 despite a decrease in production. The increase in costs on a per BOE
basis was primarily due to increased trucking as flush production from new wells exceeded facility capacity, increased chemical costs for
pipeline integrity and maintenance prevention programs, increased facility turnarounds and shut-in production. Facility turnarounds are
not required every year and may not be required again for an additional five years; as such, a disproportionate number of turnarounds
were required in 2019 versus prior periods.
Production costs for Q4 2019 increased by $3,315,000 compared to Q3 2019 primarily due to increased well and facility maintenance
costs, chemical and power costs due to increased power rates and consumption.
Other Income
($ 000s)
Investment income
Administrative income
Gain on sale of property
Deferred consideration
Realized loss on
risk management contracts
Unrealized loss on
risk management contracts
Three months ended
Year ended
December 31,
2019
September 30,
2019
December 31,
2018
December 31,
2019
December 31,
2018
21
64
70
346
(443)
(76)
(18)
11
25
3
301
-
(58)
282
17
43
-
302
-
-
362
64
144
75
65
176
-
1,273
1,362
(443)
(134)
979
-
-
1,603
Deferred consideration relates to a deferred gain on the sale of a two percent overriding royalty interest, which is recognized into
revenue using the same unit-of-production method as the encumbered property, plant and equipment assets.
The market value and carrying value of the investments held by the Company at December 31, 2019 was $286,000 (December 31, 2018 –
$374,000). There were no dispositions for the years ended December 31, 2019 or 2018. Dispositions that result in a gain or loss on sale
are recorded as an equity transfer between accumulated other comprehensive income and retained earnings.
The Company receives administrative income for various oil and gas administrative services provided and production equipment rentals.
During the third quarter of 2019, Bonterra entered into financial derivatives to minimize commodity price risk on crude oil sales. The
financial derivatives outstanding are for the period from October 1, 2019 to December 31, 2019 on a total of 153,000 barrels of crude oil
(approximately 1,000 barrels of oil per day for the month of October and 2,000 barrels of oil per day for the months of November and
December) at fixed Edmonton Par prices ranging from $62.90 to $65.00 CAD per barrel. For the first half of 2020, Bonterra also entered
into further financial derivatives to minimize commodity price risk on future crude oil sales. The financial derivatives outstanding are for
a total of 136,500 barrels of crude oil (approximately 1,000 barrels of oil per day for Q1 2020 and 500 barrels of oil per day for Q2 2020)
at fixed Edmonton Par prices ranging from $67.75 to $69.60 CAD per barrel for Q1 2020 and $59.50 CAD per barrel for Q2 2020. These
contracts are not considered normal sales contracts and are recorded at fair value.
General and Administration (G&A) Expense
($ 000s except $ per BOE)
Employee compensation expense
Office and administrative expense
Total G&A expense
$ per BOE
Three months ended
Year ended
December 31,
2019
September 30,
2019
December 31,
2018
December 31,
2019
December 31,
2018
1,367
550
1,917
1.68
987
185
1,172
1.05
696
699
1,395
1.19
4,569
2,304
6,873
1.53
4,633
2,645
7,278
1.51
Employee compensation expense for 2019 compared to 2018 remained primarily unchanged due to slightly lower earnings before
income taxes. The Company has a bonus plan in which the bonus pool consists of a range between 2.5 percent to 3.5 percent of
earnings before income taxes.
Office and administrative expenses for 2019 decreased by $341,000 compared to 2018 primarily due to a decrease in bank charges,
professional consulting fees and the allowance for doubtful accounts expense, which was partially offset by an increase in software and
consulting services. The increase in Q4 2019 over Q3 2019 was primarily due to increased bank charges and professional consulting fees.
22 Bonterra Energy 2019 Annual Report
Finance Costs
($ 000s except $ per BOE)
Interest on long-term debt
Other interest
Interest expense
$ per BOE
Unwinding of the discounted value of
decommissioning liabilities
Total finance costs
Three months ended
Year ended
December 31,
2019
September 30,
2019
December 31,
2018
December 31,
2019
December 31,
2018
3,337
222
3,559
3.12
798
4,357
3,586
194
3,780
3.39
731
4,511
3,444
239
3,683
3.13
762
4,445
14,540
801
15,341
3.42
3,019
18,360
14,560
905
15,465
3.21
3,069
18,534
Interest on long-term debt remained relatively unchanged for 2019 compared to 2018 due to increased interest rates as a result of
a higher net debt to earnings before income taxes, depletion and amortization (or “EBITDA” as defined by the Company’s bank
facility) ratio for 2019 due to decreased EBITDA from reduced production. Interest costs for 2019 were partially offset by lower average
long-term debt outstanding of approximately $7,828,000. Quarter-over-quarter interest on long-term debt decreased as a result of a
lower net debt to EBITDA ratio in effect for the current quarter and reduced average long-term debt of $7,740,000. Interest rates for
the current quarter are determined based on the trailing quarter and calculated by taking the ratio of total debt (excluding accounts
payable and accrued liabilities) to EBITDA (defined as net income excluding finance costs, provision for current and deferred taxes,
depletion and depreciation, share-option compensation, gain or loss on sale of assets and impairment of assets) multiplied by four.
Other interest relates primarily to amounts paid to a related party (see related party transactions) and a $7,500,000 subordinated
promissory note from a private investor. For more information about the subordinated promissory note, refer to Note 12 of the
December 31, 2019 audited annual financial statements.
A one percent increase (decrease) in the Canadian prime rate would decrease (increase) both annual net earnings and comprehensive
income by approximately $2,007,000.
Share-option Compensation
($ 000s)
December 31,
2019
September 30,
2019
December 31,
2018
December 31,
2019
December 31,
2018
Share-option compensation
319
649
449
2,147
2,710
Three months ended
Year ended
Share-option compensation is a statistically calculated value representing the estimated expense of issuing employee stock options.
The Company records a compensation expense over the vesting period based on the fair value of options granted to directors, officers
and employees.
Share-option compensation decreased by $563,000 in 2019 compared to 2018. This decline is primarily due to the higher share price
volatility on most of the options issued in 2017 (which were fully amortized in 2018) relative to the options issued in the fourth quarter of
2018 (which will be fully amortized in 2019). In addition, no options were issued in Q4 2019 compared to 1,031,000 options being issued
in Q4 2018.
Based on the outstanding options as of December 31, 2019, the Company has an unamortized expense of $172,000, of which $126,000
will be recorded for 2020 and $46,000 thereafter. For more information about options issued and outstanding, refer to Note 16 of the
December 31, 2019 audited annual financial statements.
Depletion and Depreciation, Exploration and Evaluation (E&E) and Goodwill
($ 000s)
Depletion and depreciation
Exploration and evaluation
Three months ended
Year ended
December 31,
2019
September 30,
2019
December 31,
2018
December 31,
2019
December 31,
2018
23,718
-
22,973
-
23,189
-
89,861
-
91,453
291
2019 Annual Report Bonterra Energy 23
The provision for depletion and depreciation increased in 2019 compared to 2018 primarily due to decreased production volumes. The
increase in the provision for depletion and depreciation in Q4 2019 compared to Q3 2019 is due to increased production volumes and
a decrease in the December 31, 2019 proved plus probable developed reserves.
The E&E expenses relate to expired leases.
There were no impairment provisions recorded for the year ended December 31, 2019 or 2018.
Taxes
The Company recorded a deferred income tax recovery of $19,475,000 (2018 – $3,921,000 expense). The deferred income tax recovery
is due to a decrease in the Alberta corporate income tax rate from 12 percent to 8 percent by January 1, 2022.
For additional information regarding income taxes, see Note 15 of the December 31, 2019 annual audited financial statements.
Net Earnings (Loss)
($ 000s except $ per share)
Net earnings (loss)
$ per share – basic
$ per share – diluted
Three months ended
Year ended
December 31,
2019
September 30,
2019
December 31,
2018
December 31,
2019
December 31,
2018
(1,389)
(0.04)
(0.04)
(1,276)
(0.04)
(0.04)
(10,909)
(0.33)
(0.33)
21,923
0.66
0.66
7,167
0.22
0.22
Net earnings for 2019 increased by $14,756,000 compared to 2018. The increase in net earnings was attributed to the deferred income
tax recovery as a result of a decrease in the Alberta corporate income tax rate. In addition, royalties and depletion and depreciation
were lower given the decrease in realized commodity prices and production, respectively. The increase in net earnings for 2019 was
partially offset by a decrease in oil and gas sales.
Other Comprehensive Income (Loss)
Other comprehensive income for 2019 consists of an unrealized loss before tax on investments (including investment in a related
party) of $88,000 relating to a decrease in the investments’ fair value (December 31, 2018 – unrealized loss of $376,000). Realized gains
decrease accumulated other comprehensive income as these gains are transferred to retained earnings. Other comprehensive income
varies from net earnings by unrealized changes in the fair value of Bonterra’s holdings of investments, including the investment in a
related party, net of tax.
Cash Flow from Operations
($ 000s except $ per share)
Cash flow from operations
$ per share – basic
$ per share – diluted
Three months ended
Year ended
December 31,
2019
September 30,
2019
December 31,
2018
December 31,
2019
December 31,
2018
20,767
0.62
0.62
19,774
0.59
0.59
20,509
0.61
0.61
81,132
2.43
2.43
115,963
3.48
3.48
In 2019, cash flow from operations decreased by $34,831,000 compared to 2018. This was primarily due to a decrease in revenue from
oil and gas sales, non-cash working capital and additional decommissioning liabilities settled.
The quarter-over-quarter increase in cash flow of $993,000 was also primarily due to an increase in revenue from oil and gas sales,
non-cash working capital and a crown royalty reassessment partially offset by an increase in production costs.
Related Party Transactions
Bonterra holds 1,034,523 (December 31, 2018 – 1,034,523) common shares in Pine Cliff Energy Ltd. (“Pine Cliff”) which represents
less than one percent ownership in Pine Cliff’s outstanding common shares. Pine Cliff’s common shares had a fair market value as of
December 31, 2019 of $155,000 (December 31, 2018 – $258,000). The Company provides marketing services for Pine Cliff. All services
performed were charged at estimated fair value. As at December 31, 2019, the Company had an account receivable from Pine Cliff of
$47,000 (December 31, 2018 – $71,000).
24 Bonterra Energy 2019 Annual Report
As at December 31, 2019, a loan to Bonterra provided by the Company’s CEO, Chairman of the Board and major shareholder totaled
$12,000,000 (December 31, 2018 – $12,000,000). On December 1, 2019, the loan’s interest rate increased from the Canadian charged
bank prime less 5/8th of one percent to five and a half percent and has no set repayment terms but is payable on demand. Security under
the debenture is over all the Company’s assets and is subordinated to any and all claims in favour of the syndicate of senior lenders
providing credit facilities to the Company. The Company’s bank agreement requires that the above loan can only be repaid should the
Company have sufficient available borrowing limits under the Company’s credit facility. Interest paid on this loan in 2019 was $421,000
(December 31, 2018 – $362,000).
Liquidity and Capital Resources
NET DEBT TO CASH FLOW FROM OPERATIONS
Bonterra continues to focus on monitoring overall debt while managing its cash flow, capital expenditures and dividend payments.
The Company’s net debt to twelve-month trailing cash flow ratio as of December 31, 2019 was 3.6 to 1 times (versus 2.8 to 1 times at
December 31, 2018). The higher net debt to cash flow ratio stems from a decrease in the Company’s twelve-month trailing cash flow.
Compared to year end 2018, net debt decreased by $36,131,000 in 2019 due to a stronger focus on debt reduction, a lower capital
spending program and reduced dividend payments compared to the prior year. The Company’s primary focus remains on managing its
bank debt during a period of highly volatile commodity prices. Bonterra will continue to assess its dividend and capital expenditures
compared to cash flow from operations on a quarterly basis.
WORKING CAPITAL DEFICIENCY AND NET DEBT
($ 000s)
Working capital deficiency
Long-term bank debt
Net Debt
December 31,
2019
December 31,
2018
19,745
273,065
292,810
30,281
298,660
328,941
The Company has sufficient availability on its credit facility to repay both the related party loan and the subordinated promissory note,
if required. During each quarter, the Company manages net debt by monitoring capital spending and dividends paid relative to cash
flow from operations.
Net debt is a combination of long-term bank debt and working capital. Net debt for December 31, 2019 decreased by $36,131,000
compared to December 31, 2018 primarily due to a stronger focus on debt reduction, a lower capital spending program and reduced
dividend payments compared to the prior year.
Working capital is calculated as current liabilities less current assets. The Company finances its working capital deficiency using cash
flow from operations, its long-term bank facility, share issuances, option exercises and adjustments of dividend payments. Included in
the working capital deficiency as at December 31, 2019 is $19,500,000 of debt relating to the subordinated promissory note and the
amount due to a related party.
FINANCIAL RISK MANAGEMENT
The Company has entered into physical delivery sales contracts to manage commodity risk. These contracts are considered normal sales
contracts and are not recorded at fair value in the financial statements. The Company also entered into risk management contracts to
manage commodity risk. These contracts are not considered normal sales contracts and are recorded at fair value. For more information
on physical delivery and risk management contracts in place see Note 19 of the December 31, 2019 audited annual financial statements.
CAPITAL EXPENDITURES
During the year ended December 31, 2019, the Company incurred capital expenditures of $53,627,000 (December 31, 2018 – $78,737,000).
Of the total capital invested, $44,551,000 was directed to the drilling and completion of 30 gross (23.7 net) wells and the tie-in of
27 gross (20.7 net) wells, with the remaining three wells brought on production in Q1 2020. An additional $9,076,000 was spent on
related infrastructure costs, recompletions and other capital expenditures.
LIABILITY MANAGEMENT RATIO (“LMR”) UPDATE
In 2019, 97 percent of the Company’s production was in the province of Alberta. The Company currently has an LMR rating of 1.86 in
Alberta, which has remained relatively unchanged from 2018 as lower drilling activity led to lower production volumes and a lower
three-year average for crude oil pricing. Bonterra has instituted an abandonment program in 2020 to reclaim 150 to 170 inactive well
bores over two years in order to increase its LMR ratio. Bonterra does not anticipate any regulatory impediments given its current LMR.
2019 Annual Report Bonterra Energy 25
LONG-TERM DEBT
Long-term debt represents the outstanding amounts drawn on the Company’s bank facility as described in the notes to the Company’s
audited annual financial statements. As of December 31, 2019, the Company has a bank facility with a limit of $325,000,000 (December 31,
2018 – $380,000,000) that is comprised of a $286,765,000 syndicated revolving credit facility and a $38,235,000 non-syndicated revolving
credit facility which has an accordion feature allowing the Company to obtain future funding of up to $40,000,000 for opportunities
outside of normal operations, such as acquisitions, subject to unanimous lender approval. Amounts drawn under the bank facility of
$325,000,000 at December 31, 2019 totaled $273,065,000 (December 31, 2018 – $298,660,000), nine percent lower than year-end 2018.
The interest rates for the year ended December 31, 2019 on the Company’s Canadian prime rate loan and Banker’s Acceptances range
between four to six percent. The loan is revolving to April 28, 2020 with a maturity date of April 29, 2021, subject to annual review.
The credit facilities have no fixed terms of repayment.
The available lending limits of the credit facilities are reviewed semi-annually on or before April 30 and October 31 each year based
mainly on the lender’s assessment of the Company’s reserves, future commodity prices and costs. Effective October 31, 2019, the
total credit facility was revised to $325,000,000, comprised of a $286,765,000 syndicated revolving credit facility and a $38,235,000
non-syndicated revolving credit facility. All other terms and conditions remain the same.
Advances drawn under the bank facility are secured by a fixed and floating charge debenture over the assets of the Company. In the
event the bank facility is not extended or renewed, amounts drawn under the facility would be due and payable on the maturity date.
The size of the committed credit facilities is based primarily on the value of the Company’s producing petroleum and natural gas assets
and related tangible assets as determined by the Lenders. For more information see Note 13 of the December 31, 2019 audited annual
financial statements.
SHAREHOLDERS’ EQUITY
The Company is authorized to issue an unlimited number of common shares without nominal or par value.
The Company is also authorized to issue an unlimited number of Class “A” redeemable Preferred Shares and an unlimited number of
Class “B” Preferred Shares. There are currently no outstanding Class “A” redeemable Preferred Shares or Class “B” Preferred Shares.
December 31, 2019
December 31, 2018
Issued and fully paid – common shares
Balance, beginning of year
Issued pursuant to the Company's share option plan
Transfer from contributed surplus to share capital
Number
33,388,796
–
Amount
($ 000s)
765,276
–
–
Number
33,310,796
78,000
Balance, end of period
33,388,796
765,276
33,388,796
Amount
($ 000s)
763,977
1,143
156
765,276
The Company provides a stock option plan for its directors, officers and employees. Under the plan, the Company may grant options
for up to 3,338,880 (December 31, 2018 – 3,338,880) common shares. The exercise price of each option granted will not be lower than
the market price of the common shares on the date of grant and the option’s maximum term is five years. For additional information
regarding options outstanding, see Note 16 of the December 31, 2019 audited annual financial statements.
COMMITMENTS
The Company has entered into firm service gas transportation agreements in which the Company guarantees that certain minimum
volumes of natural gas will be shipped on various gas transportation systems. Bonterra uses firm service delivery with TransCanada
Pipeline on approximately 90 percent of its natural gas production. Given that substantially all of Bonterra’s current natural gas
production is from the solution gas in oil wells, this will reduce transportation curtailments associated with interruptible service,
therefore decreasing restrictions on oil production. The terms of the various agreements expire in one to seven years.
The Company has office lease commitments for building and office equipment. The building and office equipment leases have an
average remaining life of 3.9 years.
26 Bonterra Energy 2019 Annual Report
Future minimum payments for the firm service gas transportation agreements using current tariff rates and the non-cancellable building
and office equipment leases as at December 31, 2019 are as follows:
($ 000s)
Firm service commitments
Office lease commitments
Total
Dividend Policy
2020
194
571
765
2021
148
499
647
2022
121
501
622
2023
121
487
608
2024
Thereafter
113
-
113
35
-
35
Total
732
2,058
2,790
For the year ended December 31, 2019, the Company declared and paid dividends of $4,007,000 ($0.12 per share) (December 31, 2018 –
$36,985,000) ($1.11 per share). Bonterra’s dividend policy is regularly monitored and is dependent upon production, commodity prices,
broad market conditions, cash flow from operations, debt levels and capital expenditures.
Bonterra’s capital spending and dividends to its shareholders are funded by cash flow from operating activities with the remaining free
cash flow directed to debt repayment. To the extent that the excess cash flow from operations after dividends and capital spending
is not sufficient, the shortfall may be funded by drawdowns on Bonterra’s bank facility. Bonterra intends to provide dividends to
shareholders that are sustainable by the Company while giving consideration to its liquidity and long-term operational strategy. The
level of dividends is highly dependent upon cash flow generated from operations, which may fluctuate significantly due to changes
in financial and operational performance, commodity prices, interest and exchange rates and many other factors. As such, future
dividends cannot be assured.
On March 10, 2020, the Company’s Board of Directors elected to suspend its monthly dividend, commencing in April, in response to
significant volatility in commodity markets. The dividend is expected to be reestablished when the economic environment can support
a sustained dividend payment.
QUARTERLY FINANCIAL INFORMATION
For the periods ended ($ 000s except $ per share)
Revenue – oil and gas sales
Cash flow from operations
Net earnings (loss)
Per share – basic
Per share – diluted
For the periods ended ($ 000s except $ per share)
Revenue – oil and gas sales
Cash flow from operations
Net earnings (loss)
Per share – basic
Per share – diluted
Q4
50,743
20,767
(1,389)
(0.04)
(0.04)
Q4
34,988
20,509
(10,909)
(0.33)
(0.33)
2019
Q3
47,320
19,774
(1,276)
(0.04)
(0.04)
2018
Q3
63,817
33,669
5,756
0.17
0.17
Q2
54,852
25,468
23,131
0.69
0.69
Q2
67,458
31,908
8,925
0.27
0.27
Q1
49,834
15,123
1,457
0.04
0.04
Q1
57,124
29,877
3,395
0.10
0.10
The fluctuations in the Company’s revenue and net earnings from quarter-to-quarter are caused by variations in production volumes,
realized commodity pricing and the related impact on royalties, production, G&A and finance costs. In the fourth quarter of 2018, the
Canadian oil and gas industry experienced a significant decrease in the realized price for Canadian crude oil due to extremely wide
differentials, which negatively impacted Bonterra’s Q4 2018 net earnings and cash flow, as well as its Q1 2019 cash flow. Net earnings for
Q2 2019 increased due to a deferred tax recovery from a decrease in the Alberta corporate income tax rate.
Critical Accounting Estimates
There have been no changes to the Company’s critical accounting policies and estimates as of the period ended in the
financial statements.
2019 Annual Report Bonterra Energy 27
Forward-Looking Information
Certain statements contained in this MD&A include statements which contain words such as “anticipate”, “could”, “should”, “expect”,
“seek”, “may”, “intend”, “likely”, “will”, “believe” and similar expressions, relating to matters that are not historical facts, and such
statements of our beliefs, intentions and expectations about development, results and events which will or may occur in the future,
constitute “forward-looking information” within the meaning of applicable Canadian securities legislation and are based on certain
assumptions and analysis made by us derived from our experience and perceptions. Forward-looking information in this MD&A
includes, but is not limited to: expected cash provided by continuing operations; cash dividends; future capital expenditures, including
the amount and nature thereof; oil and natural gas prices and demand; expansion and other development trends of the oil and gas
industry; business strategy and outlook; expansion and growth of our business and operations; and maintenance of existing customer,
supplier and partner relationships; supply channels; accounting policies; credit risks; and other such matters.
All such forward-looking information is based on certain assumptions and analyses made by us in light of our experience and perception
of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate in the
circumstances. The risks, uncertainties, and assumptions are difficult to predict and may affect operations, and may include, without
limitation: foreign exchange fluctuations; equipment and labour shortages and inflationary costs; general economic conditions; industry
conditions; changes in applicable environmental, taxation and other laws and regulations as well as how such laws and regulations are
interpreted and enforced; the ability of oil and natural gas companies to raise capital; the effect of weather conditions on operations and
facilities; the existence of operating risks; volatility of oil and natural gas prices; oil and gas product supply and demand; risks inherent in
the ability to generate sufficient cash flow from operations to meet current and future obligations; increased competition; stock market
volatility; opportunities available to or pursued by us; and other factors, many of which are beyond our control. The foregoing factors
are not exhaustive.
Actual results, performance or achievements could differ materially from those expressed in, or implied by, this forward-looking
information and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking information
will transpire or occur, or if any of them do, what benefits will be derived therefrom. Except as required by law, Bonterra disclaims
any intention or obligation to update or revise any forward-looking information, whether as a result of new information, future events
or otherwise.
The forward-looking information contained herein is expressly qualified by this cautionary statement.
DRILLING LOCATIONS
This MD&A discloses drilling locations in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations.
Proved locations and probable locations, which are sometimes collectively referred to as “booked locations”, are derived from the
independent reserves evaluation prepared by Sproule Associates Ltd. as of December 31, 2019 and account for drilling locations
that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on Bonterra’s
prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal
review. Unbooked locations do not have attributed reserves. Of the 700 net drilling locations identified herein, 305 are proved locations,
six are probable locations and 389 are unbooked locations. Unbooked locations have been identified by management as an estimation
based on industry practice and internal review of our multi-year drilling activities, which include an evaluation of applicable geologic,
seismic, engineering, production and reserves information. There is no certainty that Bonterra will drill all unbooked drilling locations
and, if drilled, there is no certainty that such locations will result in additional oil and gas reserves or production. The drilling locations
on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and
natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the
unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations,
some of other unbooked drilling locations are farther away from existing wells where management has less information about the
characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and, if drilled, there
is more uncertainty that such wells will result in additional oil and gas reserves or production. No locations have been assigned resources
other than reserves (“ROTR”). All drilling counts cited herein are net.
DISCLOSURE CONTROLS AND PROCEDURES
Disclosure controls and procedures (“DC&P”), as defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and
Interim Filings, are designed to provide reasonable assurance that information required to be disclosed in the Company’s annual filings,
interim fillings or other reports filed, or submitted by the Company under securities legislation is recorded, processed, summarized and
reported within the time periods specified under securities legislation and include controls and procedures designed to ensure that
information required to be disclosed is accumulated and communicated to management, including the Chief Executive Officer and
Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. The Chief Executive Officer and Chief
Financial Officer of Bonterra evaluated the effectiveness of the design and operation of the Company’s DC&P. Based on that evaluation,
the Chief Executive Officer and the Chief Financial Officer concluded that Bonterra’s DC&P were effective at December 31, 2019.
28 Bonterra Energy 2019 Annual Report
Internal Controls Over Financial Reporting
Internal control over financial reporting (“ICFR”), as defined in National Instrument 52-109, includes those policies and procedures that:
1.
2.
3.
Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions
of Bonterra;
Are designed to provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting principles and that receipts and expenditures of Bonterra are
being made in accordance with authorizations of management and Directors of Bonterra; and
Are designed to provide reasonable assurance regarding prevention or timely detection of authorized acquisition, use, or
disposition of the Company’s assets that could have a material effect on the financial statements.
The CEO and CFO have designed, or caused to be designed under their supervision, ICFR as defined in National Instrument 52-109 of
the Canadian Securities Administrators, in order 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 the Company used to design
its ICFR was in accordance with the Committee of Sponsoring Organizations of the Treadway Commission (COSO 2013).
The Company’s CEO and CFO have evaluated, or caused to be evaluated under their supervision, the effectiveness of the Company’s
internal controls over financial reporting at the financial period end of the Company and concluded that such internal controls over
financial reporting are effective as of December 31, 2019.
It should be noted that while Bonterra’s CEO and CFO believe that the Company’s internal controls and procedures provide a reasonable
level of assurance and are effective; they do not expect that these controls will prevent all errors and fraud.
2019 Annual Report Bonterra Energy 29
Management’s Responsibility for
Financial Statements
The information provided in this report, including the financial statements, is the responsibility of management. The timely preparation
of the financial statements requires that management make estimates and use judgment regarding the reported amounts of
assets and liabilities and disclosures of contingent assets and liabilities as at the date of the financial statements and the reported
amounts of revenues and expenses during the period. Such estimates primarily relate to unsettled transactions and events as at the
date of the financial statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur.
Management believes such estimates have been based on careful judgments and have been properly reflected in the accompanying
financial statements.
Management maintains a system of internal controls to provide reasonable assurance that the Company’s assets are safeguarded and
to facilitate the preparation of relevant and timely information.
Deloitte LLP has been appointed by the Shareholders to serve as the Company’s external auditors. They have examined the financial
statements and provided their auditor’s report. The audit committee has reviewed these financial statements with management and
the auditors, and has reported to the Board of Directors. The Board of Directors has approved the financial statements as presented in
this annual report.
George F. Fink
Chief Executive Officer and
Chairman of the Board
Robb D. Thompson
Chief Financial Officer
March 10, 2020
March 10, 2020
30 Bonterra Energy 2019 Annual Report
Independent Auditor’s Report
To the Shareholders of Bonterra Energy Corp.
Opinion
We have audited the financial statements of Bonterra Energy Corp. (the “Company”), which comprise the statement of financial position
as at December 31, 2019 and 2018, and the statement of comprehensive income, statement of changes in equity and statement of cash
flow for the years then ended, and notes to the financial statements, including a summary of significant accounting policies (collectively
referred to as the “financial statements”).
In our opinion, the accompanying financial statements present fairly, in all material respects, the financial position of the Company as at
December 31, 2019 and 2018, and its financial performance and its cash flows for the years then ended in accordance with International
Financial Reporting Standards (“IFRS”).
Basis for Opinion
We conducted our audit in accordance with Canadian generally accepted auditing standards (“Canadian GAAS”). Our responsibilities
under those standards are further described in the Auditor’s Responsibilities for the Audit of the 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 financial
statements in Canada, and we have fulfilled our other ethical responsibilities in accordance with these requirements. We believe that
the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.
Other Information
Management is responsible for the other information. The other information comprises:
• Management’s Discussion and Analysis
• The information, other than the financial statements and our auditor’s report thereon, in the Annual Report.
Our opinion on the financial statements does not cover the other information and we do not and will not express any form of assurance
conclusion thereon. In connection with our audit of the financial statements, our responsibility is to read the other information identified
above and, in doing so, consider whether the other information is materially inconsistent with the financial statements or our knowledge
obtained in the audit, or otherwise appears to be materially misstated.
We obtained Management’s Discussion and Analysis prior to the date of this auditor’s report. If, based on the work we have performed
on this other information, we conclude that there is a material misstatement of this other information, we are required to report that fact
in this auditor’s report. We have nothing to report in this regard.
The Annual Report is expected to be made available to us after the date of the auditor’s report. If, based on the work we will perform
on this other information, we conclude that there is a material misstatement of this other information, we are required to report that
fact to those charged with governance.
Responsibilities of Management and Those Charged with Governance for the
Financial Statements
Management is responsible for the preparation and fair presentation of the financial statements in accordance with IFRS, and for such
internal control as management determines is necessary to enable the preparation of financial statements that are free from material
misstatement, whether due to fraud or error.
In preparing the 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.
2019 Annual Report Bonterra Energy 31
Auditor’s Responsibilities for the Audit of the Financial Statements
Our objectives are to obtain reasonable assurance about whether the 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 GAAS 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 financial statements.
As part of an audit in accordance with Canadian GAAS, we exercise professional judgment and maintain professional skepticism
throughout the audit. We also:
• Identify and assess the risks of material misstatement of the 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 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 financial statements, including the disclosures, and whether the
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 David Langlois.
Chartered Professional Accountants
Calgary, Alberta
March 10, 2020
32 Bonterra Energy 2019 Annual Report
Statement of Financial Position
As at ($ 000s)
ASSETS
CURRENT
Accounts receivable
Crude oil inventory
Prepaid expenses
Investments
Investment in related party
Exploration and evaluation assets
Property, plant and equipment
Investment tax credit receivable
Goodwill
LIABILITIES
CURRENT
Accounts payable and accrued liabilities
Risk management contract
Due to related party
Subordinated promissory note
Deferred consideration
Bank debt
Deferred consideration
Decommissioning liabilities
Deferred tax liability
SHAREHOLDERS' EQUITY
Share capital
Contributed surplus
Accumulated other comprehensive loss
Retained earnings (deficit)
Note
December 31,
2019
December 31,
2018
6
7
8
15
9
10
19
11
12
13
14
15
16
21,764
672
3,908
131
26,475
155
3,980
955,536
8,861
92,810
7,797
613
3,183
116
11,709
258
4,422
985,773
8,861
92,810
1,087,817
1,103,833
25,423
134
12,000
7,500
1,163
46,220
273,065
12,266
138,171
114,146
583,868
765,276
30,234
(748)
(290,813)
503,949
18,743
-
12,000
10,000
1,247
41,990
298,660
13,455
132,134
133,624
619,863
765,276
28,087
(664)
(308,729)
483,970
1,087,817
1,103,833
Commitments and contingencies
Subsequent events
20
19,21
See accompanying notes to these financial statements.
On behalf of the Board:
George F. Fink
Director
Rodger A. Tourigny
Director
2019 Annual Report Bonterra Energy 33
Statement of Comprehensive Income
FOR THE YEARS ENDED DECEMBER 31
($ 000s, except $ per share)
REVENUE
Oil and gas sales, net of royalties
Other income
Deferred consideration
Loss on risk management contracts
EXPENSES
Production
Office and administration
Employee compensation
Finance costs
Share-option compensation
Depletion and depreciation
Exploration and evaluation
EARNINGS BEFORE INCOME TAXES
TAXES
Current income tax expense (recovery)
Deferred income tax expense (recovery)
NET EARNINGS FOR THE YEAR
OTHER COMPREHENSIVE INCOME (LOSS)
Unrealized (loss) on investments
Deferred taxes on unrealized loss on investments
OTHER COMPREHENSIVE (LOSS) FOR THE YEAR
TOTAL COMPREHENSIVE INCOME FOR THE YEAR
NET EARNINGS PER SHARE – BASIC AND DILUTED
COMPREHENSIVE INCOME PER SHARE – BASIC AND DILUTED
See accompanying notes to these financial statements.
Note
2019
2018
17
18
19
5
8
7
15
15
16
16
188,475
199,566
283
1,273
(577)
241
1,362
-
189,454
201,169
69,673
2,304
4,569
18,360
2,147
89,861
-
186,914
2,540
92
(19,475)
(19,383)
21,923
(88)
4
(84)
21,839
0.66
0.65
69,861
2,645
4,633
18,534
2,710
91,453
291
190,127
11,042
(46)
3,921
3,875
7,167
(376)
51
(325)
6,842
0.22
0.21
34 Bonterra Energy 2019 Annual Report
Statement of Cash Flow
FOR THE YEARS ENDED DECEMBER 31
($ 000s)
OPERATING ACTIVITIES
Net earnings
Items not affecting cash
Deferred income taxes
Deferred consideration
Share-option compensation
Depletion and depreciation
Exploration and evaluation expenditures
Unrealized loss on risk management contracts
Gain on sale of property and equipment
Unwinding of the discount on decommissioning liabilities
Investment income
Interest expense
Change in non-cash working capital accounts:
Accounts receivable
Crude oil inventory
Prepaid expenses
Investment tax credit receivable
Accounts payable and accrued liabilities
Decommissioning expenditures
Interest paid
CASH PROVIDED BY OPERATING ACTIVITIES
FINANCING ACTIVITIES
Increase (decrease) of bank debt
Subordinated promissory note
Stock option proceeds
Dividends
CASH USED IN FINANCING ACTIVITIES
INVESTING ACTIVITIES
Investment income received
Exploration and evaluation expenditures
Property, plant and equipment expenditures
Proceeds on sale of property
Change in non-cash working capital accounts:
Accounts payable and accrued liabilities
Accounts receivable
CASH USED IN INVESTING ACTIVITIES
NET CHANGE IN CASH IN THE YEAR
Cash, beginning of year
CASH, END OF YEAR
See accompanying notes to these financial statements.
Note
2019
2018
21,923
7,167
19
14
14
7
8
(19,475)
(1,273)
2,147
89,861
-
134
(75)
3,019
(64)
15,340
3,921
(1,362)
2,712
91,453
291
-
-
3,069
(65)
15,465
(13,854)
11,749
(10)
(725)
-
2,129
(2,605)
(15,340)
81,132
(25,595)
(2,500)
-
(4,007)
(32,102)
64
-
(53,627)
95
4,551
(113)
(49,030)
–
–
–
49
(648)
(27)
(1,000)
(1,346)
(15,465)
115,963
6,448
(2,500)
1,143
(36,985)
(31,894)
65
(535)
(78,202)
-
(6,387)
990
(84,069)
–
–
–
2019 Annual Report Bonterra Energy 35
Statement of Changes in Equity
FOR THE YEARS ENDED
($ 000’s, except number of shares outstanding)
Numbers of
common shares
outstanding
(Note 16)
Share
Capital
(Note 16)
Contributed
surplus(1)
JANUARY 1, 2018
33,310,796
763,977
Share-option compensation
25,533
2,710
Exercise of options
78,000
1,143
Accumulated
other
Comprehensive
loss(2)
(339)
Retained
earnings
(deficit)
(278,911)
Transfer to share capital on
exercise of options
Comprehensive income (loss)
Dividends
DECEMBER 31, 2018
33,388,796
765,276
Share-option compensation
Comprehensive income (loss)
Dividends
156
(156)
28,087
2,147
(325)
7,167
(36,985)
(664)
(308,729)
(84)
21,923
(4,007)
Total
shareholders’
equity
510,260
2,710
1,143
-
6,842
(36,985)
483,970
2,147
21,839
(4,007)
DECEMBER 31, 2019
33,388,796
765,276
30,234
(748)
(290,813)
503,949
(1) All amounts reported in Contributed Surplus relate to share-option compensation.
(2) Accumulated other comprehensive income is comprised of unrealized gains and losses on investments fair value through other comprehensive income.
See accompanying notes to these financial statements.
36 Bonterra Energy 2019 Annual Report
Notes to the Financial Statements
As at and for the years ended December 31, 2019 and 2018
1. Nature of Business and Segment Information
Bonterra Energy Corp. (“Bonterra” or the “Company”) is a public company listed on the Toronto Stock Exchange (the “TSX”) and
incorporated under the Business Corporations Act (Alberta). The address of the Company’s registered office is Suite 901, 1015-4th Street
SW, Calgary, Alberta, Canada, T2R 1J4.
Bonterra operates in one industry and has only one reportable segment being the development and production of oil and natural gas
in the western Canadian Sedimentary Basin.
2. Basis of Preparation
A) STATEMENT OF COMPLIANCE
These financial statements have been prepared by management in accordance with International Financial Reporting Standards (IFRS).
The financial statements were authorized for issue by the Company’s Board of Directors on March 10, 2020.
B) BASIS OF MEASUREMENT
These financial statements have been prepared on a historical cost basis, except for certain financial instruments and share-based
payment transactions which are measured at fair value.
C) FUNCTIONAL AND PRESENTATION CURRENCY
The Company’s functional and presentation currency is the Canadian dollar.
Foreign currency denominated monetary assets and liabilities are translated into Canadian dollars at the rates prevailing on the reporting
date. Non-monetary assets and liabilities are translated into Canadian dollars at the rates prevailing on the transaction dates. Exchange
gains and losses are recorded as income or expense in the period in which they occur.
D) SIGNIFICANT ACCOUNTING ESTIMATES AND JUDGMENTS
The timely preparation of financial statements requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and liabilities as at the date of the statement of financial position
as well as the reported amounts of revenues, expenses and cash flows during the periods presented. Such estimates relate primarily
to unsettled transactions and events as of the date of the financial statements. Actual results could differ materially from estimated
amounts. See Note 4 for more information.
E) ADOPTED ACCOUNTING PRONOUNCEMENTS
IFRS 16 “Leases”
As of January 1, 2019, the Company adopted IFRS 16 which replaces sections 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 introduces a single lease accounting model for lessees which requires the recognition of a right of
use asset and a lease liability on the statement of financial position for contracts that are, or contain, a lease.
The Company adopted IFRS 16 using the modified retrospective approach. Under this method of adoption, the right of use assets
recognized were measured at amounts equal to the present value of the lease obligations. The modified retrospective approach does
not require restatement of prior period financial information as it recognizes the cumulative effect of IFRS 16 as an adjustment to
opening retained earnings and applies the standard prospectively. The Company elected not to apply lease accounting to certain
leases for which the lease term ends within 12 months of the date of initial adoption. The Company undertook a complete evaluation of
the contracts it has entered into, and it was determined that there is no material impact as a result of adopting IFRS 16.
2019 Annual Report Bonterra Energy 37
IFRS 3 “Business Combinations”
The Company elected to early adopt the amendments to IFRS 3 “Business Combinations” effective January 1, 2019, which has been
applied prospectively to acquisitions that occur on or after January 1, 2019. The amendments introduce an optional concentration test,
narrow the definitions of a business and outputs, and clarify that an acquired set of activities and assets must include an input and a
substantive process that together significantly contribute to the ability to create outputs. These amendments do not result in changes
to the Company’s accounting policies for applying the acquisition method.
3. Significant Accounting Policies
A) REVENUE RECOGNITION
Revenue associated with the sale of crude oil, natural gas and natural gas liquids is measured based on the consideration specified in
contracts with customers. Revenue from contracts with customers is recognized when or as Bonterra satisfies a performance obligation
by transferring a promised good or service to a customer. A good or service is transferred when the customer obtains control of that
good or service. The transfer of control of oil, natural gas, and natural gas liquids usually coincides with title passing to the customer
and the customer taking physical possession. The Company principally satisfies its performance obligations at a point in time and
the amounts of revenue recognized relating to performance obligations satisfied over time are not significant. Collection of revenue
associated with the sale of crude oil, natural gas and natural gas liquids occurs on or about the 25th of the month following production.
Items such as royalties for crown, freehold, gross overriding (GORR) and Saskatchewan surcharge are netted against revenue. These
items are netted to reflect the deduction for other parties’ proportionate share of the revenue. Administration fee income is recorded
when services are provided.
B) JOINT ARRANGEMENTS
Certain exploration, development and production activities are conducted jointly with others. These financial statements reflect only
the Company’s interests in such activities. A jointly controlled operation involves the use of assets and other resources of the Company
and those of other joint venture participants through contractual arrangements rather than through the establishment of a corporation,
partnership or other entity. The Company has no interests in jointly controlled entities. The Company recognizes in its financial statements
its interest in assets that it owns, the liabilities and expenses that it incurs and its share of income earned by the joint arrangement.
C) INVENTORIES
Inventories consist of crude oil. Crude oil stored in the Company’s tanks is valued on a first-in, first-out basis at the lower of cost
or net realizable value. The inventory cost for crude oil is determined based on the combined average per barrel operating costs,
and depletion and depreciation for the period, while net realizable value is determined based on estimated sales price less
transportation costs.
D) INVESTMENTS AND INVESTMENT IN RELATED PARTY
Investments and investment in related party consist of equity securities. The Company’s investments are measured as fair value through
other comprehensive income (“FVTOCI”), with gains or losses arising from changes in fair value recognized in other comprehensive
income and accumulated in the fair value instrument. The cumulative gain or loss will not be reclassified to profit or loss on disposal
of the investments. Fair value is determined by multiplying the period end trading price of the investments by the number of common
shares held as at period end.
E) EXPLORATION AND EVALUATION ASSETS
General exploration and evaluation (“E&E”) expenditures incurred prior to acquiring the legal right to explore are charged to expense
as incurred.
E&E expenditures represent undeveloped land costs, licenses and exploration well costs.
Undeveloped land costs, licenses and exploration well costs are initially capitalized and, if subsequently determined to have not found
sufficient reserves to justify commercial production, are charged to expense. E&E assets continue to be capitalized as long as sufficient
progress is being made to assess the reserves and economic viability of the asset. Once technical feasibility and commercial viability
has been established, E&E assets are transferred to property, plant and equipment (“PP&E”). E&E assets are assessed for impairment
annually, upon transfer to PP&E assets or whenever indications of impairment exist to ensure they are not at amounts above their
recoverable amounts.
38 Bonterra Energy 2019 Annual Report
F) PROPERTY, PLANT AND EQUIPMENT
PP&E assets include transferred-in E&E costs, development drilling and other subsurface expenditures. PP&E assets are carried at cost
less depletion and depreciation of all development expenditures and include all other expenditures associated with PP&E assets.
Oil and Gas Properties
The initial cost of an asset is comprised of its purchase price or construction cost, including expenditures such as drilling costs; the
present value of the initial and changes in the estimate of any decommissioning obligation associated with the asset; and finance
charges on qualifying assets that are directly attributable to bringing the asset into operation and to its present location.
Production Facilities
Production facilities are comprised of costs related to petroleum and natural gas plant and production equipment.
Leases
Leases or contractual obligations are capitalized as right of use assets (“ROUs”) with a corresponding right of use lease obligation
using the present value of future lease payments on the statement of financial position. The discount rate used to determine the ROU
is the stated rate in the lease contract. If no discount rate is provided, the Company’s incremental borrowing rate is used. Certain lease
payments will continue to be expensed in the statement of comprehensive income. These leases are contractual obligations that
contain any of the following: are equal to or less than twelve months; are for oil and gas extraction; are variable payments; the Company
does not control the asset; or no asset is identified in the lease.
Depletion and Depreciation
Depletion and depreciation is recognized in the statement of comprehensive income (loss).
PP&E properties, excluding surface costs are depleted using the unit-of-production method over their proved plus probable developed
reserve life, when commercial production in an area has commenced. Proved plus probable developed reserves are determined annually
by qualified independent reserve engineers. Changes in factors such as estimates of proved plus probable developed reserves that
affect unit-of-production calculations are accounted for on a prospective basis. Surface costs such as production facilities and furniture,
fixtures and other equipment are depreciated over their estimated useful lives.
Production facilities, furniture, fixtures and other equipment are depreciated over the individual assets’ estimated economic lives, less
estimated salvage value of the assets at the end of their useful lives.
These assets are depreciated as follows:
Production facilities
Declining balance method at 10 percent per year
Furniture, fixtures and other equipment
Declining balance method at 10 to 20 percent per year
Right of use assets
Straight line method over the term of the associated lease
G) BUSINESS COMBINATIONS AND GOODWILL
The purchase price used in a business combination is based on the fair value at the date of acquisition. The business combination is
accounted for based on the fair value of the assets acquired and liabilities assumed. All acquisition costs are expensed as incurred.
Contingent liabilities are recognized at fair value at the date of the acquisition, and subsequently re-measured at each reporting period
until settled. The excess of cost over fair value of the net assets and liabilities acquired is recorded as goodwill.
H) IMPAIRMENT OF ASSETS
Impairment of Financial Assets
A financial asset is considered to be impaired if objective evidence indicates that one or more events have had a negative effect on the
estimated future cash flow of that asset. An impairment loss in respect of a financial asset measured at amortized cost is calculated as
the difference between its carrying amount and the present value of the estimated future cash flow discounted at the original effective
interest rate. Significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed
collectively in groups that share similar credit risk characteristics.
All impairment losses are recognized in net earnings. An impairment loss is reversed if there is an indicator that the impairment reversal
can be related objectively to an event occurring after the impairment loss was recognized. Any subsequent recovery of an impairment
loss in respect of an investment in an equity instrument classified as FVTOCI is reversed through other comprehensive income instead
of net earnings. For financial assets measured at amortized cost, the reversal is recognized in net earnings.
2019 Annual Report Bonterra Energy 39
Impairment of Non-Financial Assets
The carrying amounts of the Company’s non-financial assets are reviewed at the end of each reporting period to determine whether
there is any indication of impairment. If such indication exists, then the assets’ carrying amounts are assessed for impairment.
For the purpose of impairment testing, assets (which include E&E, PP&E and goodwill) are grouped together into the smallest
group of assets that generate cash flows from continuing use which are largely independent of the cash flow of other assets or
groups of assets (the cash-generating unit or “CGU”). Goodwill is allocated to the CGU expected to benefit from the synergies of the
combination. The recoverable amount of an asset or a CGU is the greater of its value-in-use (“VIU”) and its fair value less costs to sell
(“FVLCS”). The Company has a core CGU composed of its Alberta properties and secondary CGUs for its British Columbia (BC) and
Saskatchewan properties.
An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its recoverable amount. Impairment losses are
recognized in the statement of comprehensive income (loss). Impairment losses recognized in respect of a CGU are allocated first to
reduce the carrying amount of any goodwill allocated to the CGU and then to reduce the carrying amount of the other assets of the
CGU on a pro-rata basis.
In respect of assets other than goodwill, impairment losses recognized in prior periods are assessed at each reporting date for any
indications that the impairment loss has reversed. If the amount of the impairment loss reverses in a subsequent period and the reversal
can be objectively related to an event occurring after the impairment was recognized, the impairment loss is reversed only to the
extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depletion and
depreciation, if no impairment loss had been recognized and recorded in the statement of comprehensive income (loss). An impairment
loss in respect of goodwill cannot be reversed.
I) DEFERRED CONSIDERATION
Deferred consideration is generated when a sale of a royalty interest linked to production at a specific property occurs. Consideration
is given to the specific terms of each arrangement to determine whether a disposal of an interest in the reserves of the respective
property has occurred and whether the counterparty is entitled to the associated risks and rewards attributable to the property over
its estimated life. These include the contractual terms and implicit obligations related to production, such as the holder of the royalty
having the option of either being paid in cash or in kind and the associated commitments, if any, to develop future expansions or
projects at the property.
Proceeds for sale of a royalty interest on petroleum properties are then attributed to two components: a payment for partial disposal of
an interest in PP&E; and an upfront payment received for future extraction services that will generate future royalties. Discounted future
cash flows of future development and operating costs multiplied by the royalty rate are used to derive the upfront payment received
for future extraction services, which is accounted for as deferred consideration and recognized as revenue over the reserve life of the
encumbered properties (as this represents the efforts incurred towards the extraction performance obligation). Upon commencement
of the royalty interest the deferred consideration is depleted (recognized into revenue) using the same unit-of-production method as
the depletion of the encumbered PP&E asset’s carrying value.
J) DECOMMISSIONING LIABILITIES
The fair value of the statutory, contractual, constructive or legal liabilities associated with the retirement and reclamation of oil and
gas properties is recorded when incurred, with a corresponding increase to the carrying amount of the related PP&E. The amount
recognized is the estimated cost of decommissioning, discounted to its present value using the Company’s risk-free rate. Changes in the
estimated timing of decommissioning or decommissioning cost estimates and changes to the risk-free rates are dealt with prospectively
by recording an adjustment to the decommissioning liabilities, and a corresponding adjustment to PP&E. The unwinding of the discount
on the decommissioning provision is charged to net earnings as a finance cost.
The Company recognizes a decommissioning liability in the period in which it is incurred when a reasonable estimate of the liability
can be made. On a periodic basis, management will review these estimates and changes and if there are any, they will be applied
prospectively. The fair value of the estimated provision is recorded as a long-term liability, with a corresponding increase in the carrying
amount of the related asset. The capitalized amount is depleted on a unit-of-production basis over the life of the proved plus probable
developed reserves. The liability amount is increased each reporting period due to the passage of time and this amount is charged to
earnings in the period. Actual costs incurred upon settlement of the obligations are charged against the provision to the extent of the
liability recorded and any remaining balance of actual costs is recorded in the statement of comprehensive income (loss).
40 Bonterra Energy 2019 Annual Report
K) INCOME TAXES
Tax expense comprises current and deferred taxes. Tax is recognized in the statement of comprehensive income (loss) or directly
in equity.
Current tax expense is based on the results for the period as adjusted for items that are not taxable or not deductible. Current tax is
calculated using tax rates and laws that are substantively enacted at the end of the reporting period. Management periodically evaluates
positions taken in tax returns with respect to situations in which applicable tax regulation is subject to interpretation. Provisions are
established where appropriate on the basis of amounts expected to be paid to the tax authorities.
Deferred tax is recognized using the liability method, providing for unused tax losses, unused tax credits and temporary differences
between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes.
Deferred tax is not recognized for the following temporary differences: the initial recognition of assets and liabilities in a transaction
that is not a business combination and that affects neither accounting nor taxable profit, and differences relating to investments in
subsidiaries to the extent that they are unlikely to be reversed in the foreseeable future. Deferred tax is measured at the tax rates that
are expected to be applied to the temporary differences when they reverse, based on the laws that have been enacted or substantively
enacted by the reporting date.
A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be available against which unused
tax losses, unused tax credits and temporary differences can be utilized. Deferred tax assets are reviewed at each period end and are
reduced to the extent that it is no longer probable that the related tax benefit will be realized.
The amount and timing of reversals of temporary differences will also depend on the Company’s future operating results, and acquisitions
and dispositions of assets and liabilities. A significant change in any of the preceding assumptions could materially affect the Company’s
estimate of the deferred income tax asset or liability.
L) SHARE-OPTION COMPENSATION
The Company accounts for share-option compensation using the fair-value method of accounting for stock options granted to directors,
officers, employees and other service providers using the Black-Scholes option pricing model. Share-option payments are recognized
through the statement of comprehensive income (loss) over the vesting period with a corresponding amount reflected in contributed
surplus in equity. For awards issued in tranches that vest at different times, the fair value of each tranche is recognized over its respective
vesting period.
At the grant date and at the end of each reporting period, the Company assesses and re-assesses for subsequent periods its estimates
of the number of awards that are expected to vest and recognizes the impact of the revisions in the statement of comprehensive income
(loss). Upon exercise of share-based options, the proceeds received net of any transaction costs and the fair value of the exercised
share-based options is credited to share capital.
Employees may elect to have the Company settle any or all options vested and exercisable using a cashless equity settlement. In
connection with any such exercise, an employee shall be entitled to receive, without any cash payment (other than the taxes required to
be paid in connection with the exercise), whole shares of the Company. The number of shares under option multiplied by the difference
of the fair value at the time of exercise less the option exercise price, divided by the fair value at the time of exercise, determines the
number of whole shares issued.
M) FINANCIAL INSTRUMENTS
The Company classifies its financial instruments into one of the following categories: financial assets at amortized cost, financial liabilities
at amortized costs; and fair value through profit or loss. All financial instruments are measured at fair value on initial recognition.
Measurement in subsequent periods is dependent on the classification of the respective financial instrument.
Fair value through profit or loss financial instruments are subsequently measured at fair value with changes in fair value recognized in net
earnings. All other categories of financial instruments are measured at amortized cost using the effective interest rate method.
Cash, account receivables and certain other long-term assets are classified as financial assets at amortized cost since it is the Company’s
intention to hold these assets to maturity and the related cash flows are mainly payments of principle and interest. The Company’s
investments are measured at FVTOCI, with gains or losses arising from changes in fair value recognized in other comprehensive income
and accumulated in the fair value instrument. The cumulative gain or loss will not be reclassified to profit or loss on disposal of the
investments. Accounts payable, accrued liabilities, and certain other long-term liabilities and long-term debt are classified as financial
liabilities at amortized cost. Risk management assets and liabilities are classified as fair value through profit or loss.
2019 Annual Report Bonterra Energy 41
N) FAIR VALUE MEASUREMENT
Financial instruments consisting of accounts receivable, accounts payable and accrued liabilities, due to related party, subordinated
promissory note and bank debt on the statement of financial position are carried at amortized cost. Investments and investment in
related party are carried at fair value. All of the investments are transacted in active markets. Bonterra determines the fair value of these
transactions according to the following hierarchy based on the amount of observable inputs used to value the instrument.
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.
Bonterra’s investments and investments in related party have been assessed on the fair value hierarchy described above and are all
considered Level 1.
O) RISK MANAGEMENT CONTRACTS
The Company is exposed to market risks resulting from fluctuations in commodity prices, foreign currency exchange rates and interest
rates in the normal course of its business. The Company may use a variety of instruments to manage these exposures. For transactions
where hedge accounting is not applied, the Company accounts for such instruments using the fair value method by initially recording
an asset or liability and recognizing changes in the fair value of the instruments in earnings as unrealized gains or losses on risk
management contracts. Fair values of financial instruments are based on third party quotes or valuations provided by independent third
parties. Any realized gains or losses on risk management contracts are recognized in net earnings in the period they occur. Bonterra’s
risk management contracts have been assessed on the fair value hierarchy described above and are all considered Level 2.
P) NET EARNINGS AND COMPREHENSIVE INCOME PER SHARE
Per share amounts are calculated by dividing the net earnings or comprehensive income (loss) attributable to common shareholders of
the Company by the weighted average number of common shares outstanding during the reporting period.
Diluted per share amounts are calculated similar to basic per share amounts except that the weighted average common shares
outstanding are increased to include additional common shares from the assumed exercise of dilutive share-options. The number of
additional outstanding common shares is calculated by assuming that the outstanding in-the-money share-options were exercised and
that the proceeds from such exercises were used to acquire common shares at the average market price during the reporting period.
4. Significant Accounting Estimates and Judgments
Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the
year in which the estimates are revised and in any future years affected. The following are the estimates and judgments applied by
management that most significantly affect the Company’s financial statements.
EXPLORATION AND EVALUATION EXPENDITURES
E&E costs are initially capitalized with the intent to establish commercially viable reserves. E&E assets include undeveloped land and
costs related to exploratory wells. The Company is required to make estimates and judgments about future events and circumstances
regarding the future economic viability of extracting the underlying resources. Changes to project economics, resource quantities,
expected production techniques, unsuccessful drilling, expired mineral leases, production costs and required capital expenditures are
important factors when making this determination. To the extent a judgment is made that the underlying reserves are not viable, the
E&E costs will be impaired and charged to net earnings.
IMPAIRMENT OF NON-FINANCIAL ASSETS
PP&E and goodwill are aggregated into CGUs based on their ability to generate largely independent cash flows and are assessed
for impairment. CGUs have been determined based on similar geological structure, shared infrastructure, geographical proximity,
commodity type, and similar market risks. Oil and gas prices and other assumptions will change in the future, which may impact the
Company’s recoverable amounts and may therefore require a material adjustment to the carrying value of PP&E. The determination
of the Company’s CGUs is subject to management’s judgment. The Company has a core CGU composed of its Alberta properties and
secondary CGUs for its BC and Saskatchewan properties.
42 Bonterra Energy 2019 Annual Report
The recoverable amount of E&E, PP&E, and goodwill is determined based on the fair value less costs of disposal using a discounted
cash flow model and is assessed at the CGU level. The period the Company used to project cash flows is approximately 50 years or the
CGUs reserve life. Growth in cash flow from a single well would be determined based on the extent of total reserves assigned, which is
produced at declining rates over the estimated reserve life. The fair value measurement of the Company’s E&E, PP&E, and goodwill is
designated Level 3 on the fair value hierarchy.
The Company performs an impairment test on all of its CGUs for any potential impairment or related recovery at least annually or when
impairment or recovery indicators arise. For the year ended December 31, 2019 the Company also performed an impairment test due to
a decrease in market capitalization for Bonterra and other Canadian Oil and Gas producers. In making these evaluations, the Company
uses the following information:
1)
The net present value of the pre-tax cash flows from oil and gas reserves of each CGU based on reserves estimated by the
Company’s independent reserve evaluator; and
Key input estimates used in the determination of cash flows from oil and gas reserves include the following:
a)
b)
Reserves – Assumptions that are valid at the time of reserve estimation may change significantly when new information becomes
available. Changes in forward price estimates, production costs or recovery rates may change the economic status of reserves
and may ultimately result in reserves being revised.
Crude oil and natural gas prices – Forward price estimates of the crude oil and natural gas prices are used in the discounted
cash flow model. These prices are adjusted for quality differentials, heat content and distance to market. Commodity prices have
fluctuated widely in recent years due to global and regional factors including supply and demand fundamentals, inventory levels,
exchange rates, weather, economic and geopolitical factors.
The following table from external sources outlines the forecast benchmark commodity prices used in the impairment calculation as at
December 31, 2019.
BONTERRA‘S KEY ASSUMPTIONS FOR IMPAIRMENT
WTI Crude oil $US/Bbl(1)
AECO C-Spot $Mmbtu(1)
Exchange rate US$/Cdn$
2020
61.00
2.04
0.76
2021
65.00
2.27
0.77
2022
67.00
2.81
0.80
2023
68.34
2.89
0.80
2024
69.71
2.98
0.80
2025
71.10
3.06
0.80
2026
72.52
3.15
0.80
2027
73.97
3.24
0.80
2028
75.45
3.33
0.80
2029
76.96
3.42
0.80
2030(2)
78.50
3.51
0.80
(1) The forecast benchmark commodity prices listed above are adjusted for quality differentials, heat content, transportation and marketing costs and other factors
specific to the Company’s operations in performing the Company’s impairment tests.
(2) Forecast benchmarks commodity prices are assumed to increase by 2.0% in each year after 2030 to end of the reserve life.
c)
Discount rate – The Company uses a pre-tax discount rate of ten percent that reflects risks specific to the assets for which the
future cash flow estimates have not been adjusted. The discount rate was determined based on the Company’s assessment of
risk based on past experience. Changes in the general economic environment could result in material changes to this estimate.
With the current key assumptions listed above, the Company performed impairment tests for each CGU and concluded that no
reasonable change in the key assumptions, such as a five percent change in commodity prices or a two percent change in the discount
rate, would result in an impairment being recorded.
RESERVES ESTIMATION
The capitalized costs of oil and gas properties and deferred consideration are depleted on a unit-of-production basis at a rate calculated
by reference to proved plus probable developed reserves determined in accordance with National Instrument 51-101 and the Canadian
Oil and Gas Evaluation handbook. Commercial reserves are determined using best estimates of oil and gas in place, recovery factors
and future oil and gas prices. Amounts used for impairment calculations are also based on estimates of crude oil and natural gas
reserves and future costs required to develop those reserves.
RISK MANAGEMENT CONTRACT
The Company accounts for such instruments using the fair value method by initially recording an asset or liability, and recognizing
changes in the fair value of the instruments in net earnings as unrealized gains or losses on risk management contracts. Fair values
of financial instruments are based on third party futures quotes for commodities. Any realized or unrealized gains or losses on risk
management contracts are recognized in net earnings in the period they occur.
2019 Annual Report Bonterra Energy 43
SHARE-OPTION COMPENSATION
The Company measures the cost of equity-settled transactions with employees by reference to the fair value of the equity instruments
at the date they are granted. Estimating the fair value requires the determination of the most appropriate valuation model for a grant,
which is dependent on the terms and conditions of the grant. This also requires the determination of the most appropriate inputs to the
valuation model including the expected life of the option, risk-free interest rates, volatility and dividend yield.
DEFERRED CONSIDERATION
Deferred consideration is incurred when the sale of a royalty interest occurs that has contractual terms or implicit obligations that
requires future performance such future development costs and operating costs. Management uses judgments in determining those
cash flows such as cost, inflation and the discount rate to determine the portion of proceeds that is deferred.
DECOMMISSIONING AND RESTORATION COSTS
Decommissioning and restoration costs will be incurred by the Company at the end of the operating lives of the Company’s oil and gas
properties. Provisions for decommissioning liabilities are based on cost estimates which can vary in response to many factors including
timing of abandonment, inflation, changes in legal requirements, new restoration techniques and interest rates.
INCOME TAXES
The Company recognizes the net deferred tax benefit or expense related to deferred income tax assets or liabilities to the extent that it
is probable that the deductible temporary differences will reverse in the foreseeable future. Assessing the recoverability of investment
tax credit receivable requires the Company to make significant estimates related to expectations of future taxable income. The provision
for income taxes is based on judgments in applying income tax law and estimates of the timing, likelihood and reversal of temporary
differences between the accounting and tax basis of assets and liabilities. The ability to realize on the deferred tax assets and investment
tax credit receivable that are recorded on the balance sheet may be compromised to the extent that any interpretation of tax law is
challenged or taxable income differs significantly from estimates.
Further details regarding accounting estimates and judgments are disclosed in Note 3.
5. Finance Costs
A breakdown of finance costs for the years ended:
($ 000s)
Interest expense on bank debt
Interest expense on amounts owing to related party
Interest expense on subordinated promissory note and other
Unwinding of the fair value of decommissioning liabilities
December 31,
2019
December 31,
2018
14,540
14,561
421
380
3,019
18,360
362
542
3,069
18,534
6. Investment in Related Party
The investment consists of 1,034,523 (December 31, 2018 – 1,034,523) common shares in Pine Cliff Energy Ltd. (“Pine Cliff”), a company
with some common directors with Bonterra. The investment in Pine Cliff represents less than one percent ownership in the outstanding
common shares of Pine Cliff and is recorded at fair value through other comprehensive income. The common shares of Pine Cliff trade
on the TSX under the symbol PNE.
44 Bonterra Energy 2019 Annual Report
7. Exploration and Evaluation Assets
($ 000s)
COST AND CARRYING AMOUNT
Balance at January 1, 2018
Additions
Transfers to property, plant and equipment
Expiry of exploration and evaluation assets
BALANCE AT DECEMBER 31, 2018
Transfers to property, plant and equipment
BALANCE AT DECEMBER 31, 2019
8. Property, Plant and Equipment
COST
($ 000s)
Balance at January 1, 2018
Additions
Transfers from exploration and evaluation assets
Adjustment to decommissioning liabilities (Note 14)
BALANCE AT DECEMBER 31, 2018
Additions
Transfers from exploration and evaluation assets
Adjustment to decommissioning liabilities (Note 14)
Disposal
4,217
535
(39)
(291)
4,422
(442)
3,980
Oil and Gas
Properties
1,318,063
60,779
39
3,780
1,382,661
38,213
442
5,623
(16)
Production
Facilities
324,729
17,319
-
-
342,048
15,360
-
-
-
Furniture
Fixtures
& Other
Equipment
2,181
104
-
-
Total
Property
Plant &
Equipment
1,644,973
78,202
39
3,780
2,285
1,726,994
54
-
-
(84)
53,627
442
5,623
(100)
BALANCE AT DECEMBER 31, 2019
1,426,923
357,408
2,255
1,786,586
ACCUMULATED DEPLETION AND DEPRECIATION
($ 000s)
Oil and Gas
Properties
Balance at January 1, 2018
Depletion and depreciation
Other
BALANCE AT DECEMBER 31, 2018
Depletion and depreciation
Disposal and other
(529,434)
(75,198)
130
(604,502)
(73,718)
(45)
Production
Facilities
(118,757)
(16,170)
-
(134,927)
(16,069)
-
Furniture
Fixtures
& Other
Equipment
(1,707)
(85)
-
(1,792)
(74)
77
Total
Property
Plant &
Equipment
(649,898)
(91,453)
130
(741,221)
(89,861)
32
BALANCE AT DECEMBER 31, 2019
(678,265)
(150,996)
(1,789)
(831,050)
CARRYING AMOUNTS AS AT:
($ 000s)
December 31, 2018
DECEMBER 31, 2019
778,159
748,658
207,121
206,412
493
466
985,773
955,536
There were no impairment losses or reversals recorded in the statement of comprehensive income for the years ended December 31,
2019 and 2018.
9. Goodwill
The amount recorded as goodwill has been fully allocated to the primary CGU, Alberta, Canada. There was no impairment loss recorded
in the statement of comprehensive income (loss) for the years ended December 31, 2019 and 2018.
2019 Annual Report Bonterra Energy 45
10. Accounts Payable and Accrued Liabilities
($ 000s)
Accounts payable
Accrued liabilities
December 31,
2019
December 31,
2018
15,744
9,679
25,423
14,489
4,254
18,743
11. Transactions with Related Parties
As at December 31, 2019, a loan to Bonterra provided by the Company’s CEO, Chairman of the Board and major shareholder totaled
$12,000,000 (December 31, 2018 – $12,000,000). On December 1, 2019, the loan’s interest rate increased from the Canadian charged
bank prime less 5/8th of one percent to five and a half percent and has no set repayment terms but is payable on demand. Security under
the debenture is over all of the Company’s assets and is subordinated to any and all claims in favour of the syndicate of senior lenders
providing credit facilities to the Company. The Company’s bank agreement requires that the above loan can only be repaid should
the Company have sufficient available borrowing limits under the Company’s credit facility. Interest paid on this loan during 2019 was
$421,000 (December 31, 2018 – $362,000).
The Company provides executive and marketing services for Pine Cliff Energy Ltd. (Pine Cliff). All services performed were
charged at estimated fair value. As at December 3, 2019, the Company had an account receivable from Pine Cliff of $47,000
(December 31, 2018 – $71,000).
COMPENSATION FOR KEY MANAGEMENT PERSONNEL
($ 000s)
Compensation
Share-based payments
Total compensation
December 31,
2019
December 31,
2018
1,708
961
2,669
1,526
1,178
2,704
Key management personnel are those persons, including all directors, having authority and responsibility for planning, directing and
controlling the activities of the Company.
12. Subordinated Promissory Note
As at December 31, 2019, Bonterra had $7,500,000 (December 31, 2018 – $10,000,000) outstanding on a subordinated note to a
private investor. On December 1, 2019, the loan’s interest rate increased from five percent to five and a half percent. The subordinated
promissory note is not callable until after June 30, 2020 and is then repayable after thirty days’ written notice by either party. Security
consists of a floating demand debenture over all of the Company’s assets and is subordinated to any and all claims in favor of the
syndicate of senior lenders providing credit facilities to the Company. Interest paid on the subordinated promissory note during 2019
was $378,000 (December 31, 2018 – $514,000).
The Company’s bank agreement requires that the above loan can only be repaid should the Company have sufficient available borrowing
limits under the Company’s credit facility.
13. Bank Debt
As at December 31, 2019, the Company has a total bank facility of $325,000,000 (December 31, 2018 – $380,000,000), comprised of a
$286,765,000 syndicated revolving credit facility and a $38,235,000 non-syndicated revolving credit facility. The amount drawn under
the total bank facility at December 31, 2019 was $273,065,000 (December 31, 2018 – $298,660,000). The amounts borrowed under the
bank facility bear interest at a floating rate based on the applicable Canadian prime rate or Banker’s Acceptance rate, plus between
0.50 percent and 3.50 percent, depending on the type of borrowing and the Company’s consolidated debt to EBITDA ratio. EBITDA
is defined as net income for the period excluding finance costs, provision for current and deferred taxes, depletion and depreciation,
share-option compensation, gain or loss on sale of assets and impairment of assets. The terms of the bank facility provide that the loan
is revolving to April 28, 2020, with a maturity date of April 29, 2021, subject to annual review. The credit facilities have no fixed terms
of repayment. The Company has an accordion feature which allows it to obtain future funding of up to $40,000,000 for opportunities
outside of normal operations, such as acquisitions, subject to unanimous lender approval.
The available lending limit of the bank facility is reviewed semi-annually on or before April 30 and October 31 and is based on the
lender’s assessment of the Company’s reserves, future commodity prices and costs.
46 Bonterra Energy 2019 Annual Report
The amount available for borrowing under the bank facility is reduced by outstanding letters of credit. Letters of credit totaling $900,000
were issued as at December 31, 2019 (December 31, 2018 – $900,000). Security for the bank facility consists of various floating demand
debentures totaling $750,000,000 (December 31, 2018 – $750,000,000) over all of the Company’s assets and a general security agreement
with first ranking over all personal and real property.
The following is a list of the material financial covenants on the bank facility:
• The Company cannot exceed $325,000,000 in consolidated debt (comprised of due to related party, subordinated promissory note
and long-term bank debt). As at December 31, 2019 consolidated debt totaled $292,565,000.
• Dividends paid in the current quarter shall not exceed 80 percent of the available cash flow for the preceding four fiscal quarters
divided by four, which is calculated as four percent for the current quarter.
Available cash flow is defined to be cash provided by operating activities excluding the change in non-cash working capital and
decommissioning liabilities settled and including investment income received and all net proceeds of dispositions included in cash
used in investing activities. As at December 31, 2019, the Company is in compliance with all covenants.
14. Decommissioning Liabilities
At December 31, 2019, the Company used a 2.0 percent inflation rate (December 31, 2018 – 2.0 percent inflation rate) and a risk-free
nominal rate of 2.3 percent (December 31, 2018 – 2.32 percent) to calculate the present value of the decommissioning provision. In 2019,
due to forces currently influencing global capital markets, long-term risk-free nominal rates in Canada declined below target inflation
rates, implying a negative real rate of return. The Company determined that applying these rates to current cost estimates would not
provide an accurate measurement of the decommissioning liability as observable stand-alone risk-free real rates of return continue to
be positive. To provide a more accurate measurement of the liability, the Company applied a risk-free real return rate of 0.3 percent to
estimate the present value of the decommissioning provision at December 31, 2019, resulting in a change in estimate. The risk-free real
return rate represents an observable, market based risk-free rate of return after adjusting for inflation. Changes in the measurement of
the decommissioning provision are added to, or deducted from, the cost of the related asset in property, plant and equipment. When a
re-measurement of the decommissioning provision relates to a retired asset, the amount is recorded in the statement of comprehensive
income (loss).
At December 31, 2019, the estimated total uninflated and undiscounted amount required to settle the decommissioning liabilities
was $155,614,000 (December 31, 2018 – $150,602,000). These obligations will be settled at the end of the useful lives of the underlying
assets, which extend up to 50 years into the future.
($ 000s)
DECOMMISSIONING LIABILITIES, JANUARY 1
Changes in estimate
Liabilities settled during the period
Unwinding of the discount on decommissioning liabilities
DECOMMISSIONING LIABILITIES, END OF YEAR
December 31,
2019
December 31,
2018
132,134
126,631
5,623
(2,605)
3,019
3,780
(1,346)
3,069
138,171
132,134
2019 Annual Report Bonterra Energy 47
15. Income Taxes
($ 000s)
Deferred tax asset (liability) related to:
Investments
Exploration and evaluation assets and property, plant and equipment
Investment tax credits
Decommissioning liabilities
Corporate tax losses carried forward
Share issue costs
Financial derivative
Corporate capital tax losses carried forward
Unrecorded benefits of capital tax losses carried forward
Unrecorded benefits of successored resource related pools
December 31,
2019
December 31,
2018
81
82
(149,134)
(172,449)
(2,041)
31,824
6,714
-
31
7,488
(7,488)
(1,621)
(2,392)
35,676
7,354
6
-
8,777
(8,777)
(1,901)
Deferred tax asset (liability)
(114,146)
(133,624)
Income tax expense varies from the amounts that would be computed by applying Canadian federal and provincial income tax rates
as follows:
($ 000s)
Earnings (loss) before taxes
Combined federal and provincial income tax rates
Income tax provision calculated using statutory tax rates
Increase (decrease) in taxes resulting from:
Change in statutory tax rates(1)
Share-option compensation
Change in unrecorded benefits of tax pools
Change in estimates and other
December 31,
2019
December 31,
2018
2,540
26.67%
677
(18,946)
573
(1,569)
(118)
(19,383)
11,042
27.00%
2,981
-
732
78
84
3,875
(1) Effective July 1, 2019 the combined federal and provincial income tax rate for Bonterra is approximately 26.00% due to the provincial tax rate for Alberta,
Canada decreasing from 12% to 11%. The provincial tax rate for Alberta will further decrease to 10% on January 1, 2020, 9% on January 1, 2021 and 8% on
January 1, 2022.
The Company has the following tax pools, which may be used to reduce taxable income in future years, limited to the applicable rates
of utilization:
($ 000s)
Undepreciated capital costs
Canadian oil and gas property expenditures
Canadian development expenditures
Canadian exploration expenditures
Federal income tax losses carried forward(1)
Provincial income tax losses carried forward(2)
Rate of
Utilization (%)
7-100
10
30
100
100
100
Amount
77,467
84,635
126,556
8,587
42,385
3,968
343,598
(1) Federal income tax losses carried forward expire in the following years: 2035 – $6,323,000; 2036 – $35,853,000; 2037 – $209,000.
(2) Provincial income tax losses carried forward expire in the following years: 2036 – $3,759,000; 2037 – $209,000.
The Company has $8,861,000 (December 31, 2018 – $8,861,000) of investment tax credits that expire in the following years:
2024 – $1,319,000; 2025 – $2,258,000; 2026 – $2,405,000; 2027– $2,009,000; 2028 – $745,000; 2034 – $99,000; and 2037 – $26,000.
The Company has $65,015,000 (December 31, 2018 – $65,015,000) of capital losses carried forward which can only be claimed against
taxable capital gains.
48 Bonterra Energy 2019 Annual Report
16. Shareholders’ Equity
AUTHORIZED
The Company is authorized to issue an unlimited number of common shares without nominal or par value.
December 31, 2019
December 31, 2018
Issued and fully paid – common shares
Number
Amount
($ 000s)
Number
Balance, beginning of year
33,388,796
765,276
33,310,796
Issued pursuant to the Company's share option plan
-
Transfer from contributed surplus to share capital
-
-
78,000
Amount
($ 000s)
763,977
1,143
156
Balance, end of year
33,388,796
765,276
33,388,796
765,276
The Company is authorized to issue an unlimited number of Class “A” redeemable Preferred Shares and an unlimited number of Class
“B” Preferred Shares. There are currently no outstanding Class “A” redeemable Preferred Shares or Class “B” Preferred Shares.
The weighted average common shares used to calculate basic and diluted net earnings per share for the year ended December 31 is
as follows:
Basic shares outstanding
Dilutive effect of share options(1)
Diluted shares outstanding
December 31,
2019
December 31,
2018
33,388,796
33,327,777
-
493
33,388,796
33,328,270
(1) The Company did not include 1,945,000 share-options (December 31, 2018 – 2,775,000) in the dilutive effect of share-options calculations as these share-options
were anti-dilutive.
For the year ended December 31, 2019, the Company declared and paid dividends of $4,007,000 ($0.12 per share) (December 31, 2018 –
$36,985,000 ($1.11 per share)).
The Company provides an equity settled option plan for its directors, officers and employees. Under the plan, the Company may grant
options for up to 3,338,880 (December 31, 2018 – 3,338,880 common shares). The exercise price of each option granted cannot be lower
than the market price of the common shares on the date of grant and the option’s maximum term is five years.
A summary of the status of the Company’s stock options as of December 31, 2019 and changes during the year ended are
presented below:
At January 1, 2018
Options granted
Options exercised
Options forfeited
Options expired
At December 31, 2018
Options granted
Options forfeited
Options expired
AT DECEMBER 31, 2019
Number of
options
Weighted
average
exercise price
2,806,000
1,073,000
(78,000)
(53,000)
(954,000)
2,794,000
60,000
(130,000)
(779,000)
1,945,000
$19.48
6.39
14.67
19.01
28.23
$11.62
5.79
11.24
14.93
$10.13
2019 Annual Report Bonterra Energy 49
The following table summarizes information about options outstanding and exercisable as at December 31, 2019:
Range of exercise prices
Number
outstanding
Options Outstanding
Weighted-average
remaining
contractual life
Options Exercisable
Weighted-average
exercise price
Number
exercisable
Weighted-average
exercise price
$ 5.00 – $ 10.00
1,041,000
10.01 – 15.00
15.01 – 25.00
818,000
86,000
$ 5.00 – $ 25.00
1,945,000
1.2 years
0.8 years
1.1 years
1.0 years
$5.92
14.55
19.05
$10.13
895,000
810,000
23,000
1,728,000
$5.93
14.56
20.23
$10.16
The Company records compensation expense over the vesting period, which ranges between one and three years, based on the fair
value of options granted to directors, officers and employees. In 2019, the Company granted 60,000 options with an estimated fair value
of $86,000 or $1.43 per option using the Black-Scholes option pricing model with the following key assumptions:
Weighted-average risk free interest rate (%)(1)
Weighted-average expected life (years)
Weighted-average volatility (%)(2)
Forfeiture rate (%)
Weighted average dividend yield (%)
December 31,
2019
December 31,
2018
1.62
2.0
49.06
7.37
2.05
1.93
1.2
46.45
7.55
2.22
(1) Risk-free interest rate is based on the weighted average Government of Canada benchmark bond yields for one, two, and three year terms to match corresponding
vesting periods.
(2) The expected volatility is measured as the standard deviation of expected share price returns based on statistical analysis of historical weekly share prices for a
representative period.
17. Oil and Gas Sales, Net of Royalties
($ 000s)
Oil and gas sales
Crude oil
Natural gas liquids
Natural gas
Less royalties:
Crown
Freehold, gross overriding royalties and other
Oil and gas sales, net of royalties
18. Other Income
($ 000s)
Investment income
Administrative income
Gain on sale of property and equipment
Other income
50 Bonterra Energy 2019 Annual Report
December 31,
2019
December 31,
2018
176,996
9,300
16,453
202,749
(7,230)
(7,044)
(14,274)
188,475
194,137
14,645
14,606
223,388
(15,157)
(8,665)
(23,822)
199,566
December 31,
2019
December 31,
2018
64
144
75
283
65
176
-
241
19. Financial Risk Management
FINANCIAL RISK FACTORS
The Company undertakes transactions in a range of financial instruments including:
• Accounts receivable
• Accounts payable and accrued liabilities
• Common share investments
• Due to related party
• Bank debt
• Subordinated promissory note
The Company’s activities result in exposure to a number of financial risks including market risk (commodity price risk, interest rate risk,
and foreign exchange risk), credit risk, liquidity risk and equity price risk.
The Company’s overall risk management program seeks to mitigate these risks and reduce the volatility on the Company’s financial
performance. Financial risk is managed by senior management under the direction of the Board of Directors.
The Company may enter into various risk management contracts to manage the Company’s exposure to commodity price fluctuations.
The Company does not speculatively trade in risk management contracts. The Company’s risk management contracts are entered into
to manage the risks relating to commodity prices from its business activities.
CAPITAL RISK MANAGEMENT
The Company’s objectives when managing capital, which the Company defines to include shareholders’ equity, debt and working
capital balances, are to safeguard the Company’s ability to continue as a going concern, so that it can continue to provide returns to
its shareholders and benefits for other stakeholders and to maintain a capital structure that provides a low cost of capital. In order to
maintain or adjust the capital structure, the Company may adjust the amount of dividends, debt facilities or issue new shares.
The Company monitors capital on the basis of the ratio of net debt (total debt adjusted for working capital) to cash flow from operating
activities. This ratio is calculated using each quarter end net debt divided by the preceding twelve months’ cash flow. Management
believes that a net debt level as high as one and a half year’s cash flow is still an appropriate level to allow it to take advantage in the
future of either acquisition opportunities or to provide flexibility to develop its undeveloped resources by horizontal or vertical drill
programs. During the current year the Company had a net debt to cash flow level of 3.6:1 compared to 2.8:1 in 2018. The increase in
net debt to cash flow ratio is primarily due to a $34,831,000 decrease in cash flow due to a decrease in production volumes, which was
partially offset by reducing net debt by $36,131,000 using excess cash flow from operations.
Section (a) of this note provides the Company’s debt to cash flow from operations.
Section (b) addresses in more detail the key financial risk factors that arise from the Company’s activities including its policies for
managing these risks.
a)
Net Debt to Cash Flow Ratio
The net debt and cash flow amounts are as follows:
($ 000s)
Bank debt
Current liabilities
Current assets
Net debt
Cash flow from operations
Net debt to cash flow ratio
December 31,
2019
December 31,
2018
273,065
46,220
(26,475)
292,810
81,132
3.6
298,660
41,990
(11,709)
328,941
115,963
2.8
2019 Annual Report Bonterra Energy 51
b) Risks and Mitigation
Market risk is the risk that the fair value or future cash flow of the Company’s financial instruments will fluctuate because of changes in
market prices. Components of market risk to which the Company is exposed are discussed below.
COMMODITY PRICE RISK
The Company’s principal operation is the production and sale of crude oil, natural gas and natural gas liquids. Fluctuations in prices of
these commodities directly impact the Company’s performance and ability to continue with its dividends.
The Company has used various risk management contracts to set price parameters for a portion of its production. The Company has
assumed the risk in respect of commodity prices, except for a small portion of physical delivery sales and risk management contracts to
manage commodity risk on the Company’s higher operating cost areas.
The Company is exposed to credit risk, liquidity risk and market risk as part of its normal course of business. The Company’s overall risk
management program seeks to mitigate these risks and reduce the volatility on the Company’s financial performance. Financial risk is
managed by senior management under the direction of the Board of Directors.
PHYSICAL DELIVERY SALES CONTRACTS
Bonterra enters into physical delivery sales contracts to manage commodity price risk. These contracts are considered normal executory
sales contracts and are not recorded at fair value in the financial statements. As of December 31, 2019, the Company has the following
physical delivery sales contracts in place.
Product
Type of Contract
Volume
Term
Oil
Gas
Gas
Fixed price – MSW Stream index(1)
1,000 BBL/day
January 1 to March 31, 2020
Fixed Price – AECO(2)
Fixed Price – AECO(2)
2,500 GJ/day
2,500 GJ/day
April 1 to October 31, 2020
April 1 to October 31, 2020
Contract Price
$64.46 CAD/BBL
$1.55 CAD/GJ
$1.64 CAD/GJ
(1) “MSW Stream index” or “Edmonton Par” refers to the mixed sweet blend that is the benchmark price for conventionally produced light sweet crude oil in
Western Canada.
(2) “AECO” refers to Alberta Energy Company; a grade or heating content of natural gas used as benchmark pricing in Alberta, Canada.
Subsequent to December 31, 2019, the Company entered into the following physical delivery sales contracts.
Product
Type of Contract
Oil
Oil
Oil
Oil
Fixed price – MSW Stream index
Fixed price – MSW Stream index
Fixed price – MSW Stream index
Fixed price – MSW Stream index
Volume
500 BBL/day
500 BBL/day
500 BBL/day
500 BBL/day
Term
April 1 to June 30, 2020
April 1 to June 30, 2020
March 1 to March 31, 2020
April 1 to June 30, 2020
Contract Price
$70.25 CAD/BBL
$62.00 CAD/BBL
$59.08 CAD/BBL
$62.91 CAD/BBL
RISK MANAGEMENT CONTRACTS
($ 000s)
Risk management contracts
Realized loss
Unrealized loss
December 31,
2019
December 31,
2018
(443)
(134)
(577)
-
-
-
52 Bonterra Energy 2019 Annual Report
The Company also enters into financial derivative instruments or risk management contracts to manage commodity price risk. These
contracts are not considered normal executory sales contracts and are recorded at fair value in the financial statements. The Company
has entered into the following risk management contracts during the year ended December 31, 2019.
Product
Type of Contract
Volume
Term
Oil
Oil
Oil
Oil
Oil
Fixed price – MSW Stream index
500 BBL/day
October 1 to December 31, 2019
Fixed price – MSW Stream index
500 BBL/day
October 1 to December 31, 2019
Fixed price – MSW Stream index
500 BBL/day
November 1 to December 31, 2019
Fixed price – MSW Stream index
500 BBL/day
January 1 to March 31, 2020
Fixed price – MSW Stream index
500 BBL/day
January 1 to March 31, 2020
Contract Price
$65.00 CAD/BBL
$63.00 CAD/BBL
$62.90 CAD/BBL
$67.75 CAD/BBL
$69.60 CAD/BBL
On March 4, 2020, the Company also entered into a financial derivative for the period of April 1, 2020 to June 30, 2020 for a total of
45,500 barrels of oil (approximately 500 barrels of oil per day) at a fixed MSW stream index price of $59.50 CAD per barrel.
INTEREST RATE RISK
Interest rate risk refers to the risk that the value of a financial instrument or cash flows associated with the instrument will fluctuate due
to changes in market interest rates. Interest rate risk arises from interest bearing financial assets and liabilities that the Company uses.
The principal exposure of the Company is on its borrowings which have a variable interest rate which gives rise to a cash flow interest
rate risk.
The Company’s debt facilities consist of a $286,765,000 syndicated revolving operating line, $38,235,000 non-syndicated operating line,
$12,000,000 due to a related party and a $7,500,000 subordinated promissory note. The borrowings under these facilities, except for
the subordinated promissory note, are at bank prime plus or minus various percentages as well as by means of banker’s acceptances
(BAs) within the Company’s credit facility. The subordinated promissory note is at a fixed interest rate of five percent. The Company
manages its exposure to interest rate risk on its floating interest rate debt through entering into various term lengths on its BAs but in
no circumstances do the terms exceed six months.
SENSITIVITY ANALYSIS
Based on historic movements and volatilities in the interest rate markets and management’s current assessment of the financial markets,
the Company believes that a one percent variation in the Canadian prime interest rate is reasonably possible over a 12-month period.
A one percent increase (decrease) in the Canadian prime rate would decrease (increase) both annual net earnings and comprehensive
income by $2,007,000.
EQUITY PRICE RISK
Equity price risk refers to the risk that the fair value of the investments and investment in related party will fluctuate due to changes in
equity markets. Equity price risk arises from the realizable value of the investments that the Company holds which are subject to variable
equity market prices which on disposition gives rise to a cash flow equity price risk. The Company will assume full risk in respect of equity
price fluctuations.
FOREIGN EXCHANGE RISK
The Company has no foreign operations and currently sells all of its product sales in Canadian currency. The Company, however, is
exposed to currency risk in that crude oil is priced in US currency, then converted to Canadian currency. The Company currently has no
outstanding risk management agreements. The Company will assume full risk in respect of foreign exchange fluctuations.
CREDIT RISK
Credit risk is the risk that a contracting party will not complete its obligations under a financial instrument and cause the Company to
incur a financial loss. The Company is exposed to credit risk on all financial assets included on the statement of financial position. To
help mitigate this risk:
• The Company only enters into material agreements with credit worthy counterparties. These include major oil and gas companies or
major Canadian chartered banks; and
• Agreements for product sales are primarily on 30-day renewal terms.
2019 Annual Report Bonterra Energy 53
Of the $21,764,000 accounts receivable balance at December 31, 2019 (December 31, 2018 – $7,797,000) over 75 percent (2018 –
74 percent) relates to product sales with national and international oil and gas companies.
On a quarterly basis, the Company assesses if there has been any impairment of the financial assets of the Company. During the year
ended December 31, 2019, there was no material impairment provision required on any of the financial assets of the Company. The
Company does have a credit risk exposure as the majority of the Company’s accounts receivable are with counterparties having similar
characteristics. However, payments from the Company’s largest accounts receivable counterparties have consistently been received
within 30 days and the sales agreements with these parties are cancellable with 30 days’ notice if payments are not received.
At December 31, 2019, approximately $276,000 or one percent of the Company’s total accounts receivable are aged over 90 days and
considered past due (December 31, 2018 – $397,000 or five percent). The majority of these accounts are due from various joint venture
partners. The Company actively monitors past due accounts and takes the necessary actions to expedite collection, which can include
withholding production or netting payables when the accounts are with joint venture partners. Should the Company determine that
the ultimate collection of a receivable is in doubt, it will provide the necessary provision in its allowance for doubtful accounts with a
corresponding charge to earnings. If the Company subsequently determines an account is uncollectable, the account is written off with
a corresponding charge to the allowance account. The Company’s allowance for doubtful accounts balance at December 31, 2019 is
$1,232,000 (December 31, 2018 – $1,402,000) with the expense being included in general and administrative expenses. There were no
material accounts written off during the period.
The maximum exposure to credit risk is represented by the carrying amounts of accounts receivable. There are no material financial
assets that the Company considers past due.
LIQUIDITY RISK
Liquidity risk includes the risk that, as a result of the Company’s operational liquidity requirements:
• The Company will not have sufficient funds to settle a transaction on the due date;
• The Company will not have sufficient funds to continue with its dividends;
• The Company will be forced to sell assets at a value which is less than what they are worth; or
• The Company may be unable to settle or recover a financial asset at all.
To help reduce these risks the Company maintains bank facilities determined by a portfolio of high-quality, long reserve life oil and
gas assets.
20. Commitments and Financial Liabilities
The Company has the following maturity schedule for its financial liabilities and commitments:
($ 000s)
Recognized
on Financial
Statements
Accounts payable and accrued liabilities
Yes – Liability
Due to related parties
Subordinated promissory note
Bank Debt
Firm service commitments
Office lease commitments
Total
Yes – Liability
Yes – Liability
Yes – Liability
No
No
Less than
1 year
25,423
12,000
7,500
-
194
571
-
-
-
273,065
269
1,000
45,688
274,334
-
-
-
-
234
487
721
-
-
-
-
35
-
35
Over 1 year
to 3 years
Over 3 years
to 5 years
Over 5 years
to 7 years
The Company has entered into firm service gas transportation agreements in which the Company guarantees certain minimum volumes
of natural gas will be shipped on various gas transportation systems. The terms of the various agreements expire in one to seven years.
The future minimum payment amounts for the firm service gas transportation agreements are calculated using current tariff rates.
The Company also has non-cancellable office lease commitments for building and office equipment. The building and office equipment
leases have an average remaining life of 3.9 years.
54 Bonterra Energy 2019 Annual Report
21. Subsequent Events
I) DIVIDENDS
Subsequent to December 31, 2019, the Company declared the following dividends:
Date declared
January 2, 2020
February 3, 2020
March 2, 2020
Record date
$ per share
Date payable
January 15, 2020
February 14, 2020
March 16, 2020
0.01
0.01
0.01
January 31, 2020
February 28, 2020
March 31, 2020
On March 10, 2020, the Company’s Board of Directors elected to suspend its monthly dividend, commencing in April 2020.
II) SHARE OPTIONS
On February 19, 2020 the Company granted 993,200 share options to employees and directors with an exercise price of $3.14, based on
the market price immediately preceding the date of grant. The share options vest between one and two years from the grant date and
expire between February 18, 2022 and 2023.
2019 Annual Report Bonterra Energy 55
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Corporate Information
Board of Directors
G. F. Fink – Chairman
G. J. Drummond
R. M. Jarock
R. A. Tourigny
A. M. Walsh
Officers
G. F. Fink, CEO and Chairman of the Board
R. D. Thompson, CFO and Corporate Secretary
A. Neumann, Chief Operating Officer
B. A. Curtis, Senior VP, Business Development
Registrar and Transfer Agent
Odyssey Trust Company
Auditors
Deloitte LLP
Solicitors
Borden Ladner Gervais LLP
Bankers
CIBC
National Bank of Canada
The Toronto Dominion Bank
ATB Financial
Business Development Bank of Canada
Head Office
901, 1015 – 4th Street SW
Calgary, Alberta T2R 1J4
TEL:
FAX:
EMAIL: info@bonterraenergy.com
403.262.5307
403.265.7488
Website
www.bonterraenergy.com
2019 Annual Report Bonterra Energy 57
901, 1015 – 4th Street SW
Calgary, Alberta, T2R 1J4
TEL 403.262.5307
FAX 403.265.7488
info@bonterraenergy.com
www.bonterraenergy.com