RESILIENT.
COMMITTED.
SUSTAINABLE.
2 0 2 0
Annual Report
T S X B T E
OUR
HIGHLIGHTS
OUR OPERATING
AREAS
79,781 boe/d
for the full-year 2020
$ 18 million
free cash flow
Extended
long-term note and credit
facility maturities to 2024
$ 319 million
liquidity
46%
reduction in GHG emissions
intensity, relative to our
2018 baseline
TABLE OF CONTENTS
5
Message
to Shareholders
45
Management’s
Report
7
Management’s
Discussion and
Analysis
WWW.BAYTEXENERGY.COM
T S X B T E
Peace River
Duvernay
Lloydminster
Viking
Eagle Ford
46
Auditors’
Reports
49
Consolidated
Financial
Statements
79
Reserves
Information
SUMMARY
FINANCIAL
(thousands of Canadian dollars, except per common share amounts)
Petroleum and natural gas sales
Adjusted funds flow (1)
Per share – basic
Per share – diluted
Net income (loss)
Per share – basic
Per share – diluted
Capital Expenditures
Exploration and development expenditures (1)
Acquisitions, net of divestitures
Total oil and natural gas capital expenditures
Net Debt
Credit facilities
Long-term notes
Long-term debt
Working capital deficiency
Net debt (1)
Shares Outstanding - basic (thousands)
Weighted average
End of period
Twelve Months Ended
December 31,
2020
December 31,
2019
$
975,477
311,506
0.56
0.56
(2,438,964)
(4.35)
(4.35)
1,805,919
902,426
1.62
1.62
(12,459)
(0.02)
(0.02)
280,340
(182)
280,158
$
$
552,291
2,180
554,471
651,173
$
1,147,950
1,799,123
48,478
1,847,601
$
560,657
561,227
506,471
1,337,200
1,843,671
28,120
1,871,791
557,048
558,305
$
$
$
$
$
Baytex Energy Corp. 2020 Annual Report
1
OPERATING
Daily Production
Light oil and condensate (bbl/d)
Heavy oil (bbl/d)
NGL (bbl/d)
Total liquids (bbl/d)
Natural gas (mcf/d)
Oil equivalent (boe/d @ 6:1) (2)
Netback (thousands of Canadian dollars)
Total sales, net of blending and other expense (3)
Royalties
Operating expense
Transportation expense
Operating netback (1)
General and administrative
Cash financing and interest
Realized financial derivatives gain (loss)
Other (4)
Adjusted funds flow (1)
Netback (per boe)
Total sales, net of blending and other expense (3)
Royalties
Operating expense
Transportation expense
Operating netback (1)
General and administrative
Cash financing and interest
Realized financial derivatives gain (loss)
Other (4)
Adjusted funds flow (1)
Twelve Months Ended
December 31,
2020
December 31,
2019
37,056
21,142
7,340
65,538
85,464
79,781
927,096 $
(163,735)
(331,345)
(28,437)
403,579 $
(34,268)
(106,534)
47,836
893
311,506 $
31.75 $
(5.61)
$
(11.35)
(0.97)
13.82
(1.17)
(3.65)
1.64
0.03
10.67 $
43,587
26,741
10,229
80,557
102,742
97,680
1,737,124
(320,241)
(397,716)
(43,942)
975,225
(45,469)
(107,417)
75,620
4,467
902,426
48.72
(8.98)
(11.16)
(1.23)
27.35
(1.28)
(3.01)
2.12
0.13
25.31
$
$
$
$
$
$
Notes:
(1)
(2)
The terms “adjusted funds flow”, “exploration and development expenditures”, “net debt” and “operating netback” do not have any standardized meaning as
prescribed by Canadian Generally Accepted Accounting Principles (“GAAP”) and therefore may not be comparable to similar measures presented by other
companies where similar terminology is used. See the advisory on non-GAAP measures at the end of this press release.
Barrel of oil equivalent ("boe") amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. The use of boe
amounts may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an
energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
(3) Realized heavy oil prices are calculated based on sales dollars, net of blending and other expense. We include the cost of blending diluent in our realized heavy
oil sales price in order to compare the realized pricing on our produced volumes to the WCS benchmark.
(4) Other is comprised of realized foreign exchange gain or loss, other income or expense, current income tax expense or recovery and share-based compensation.
Refer to the 2020 MD&A for further information on these amounts.
2
Baytex Energy Corp. 2020 Annual Report
Advisory Regarding Forward-Looking Statements
In the interest of providing Baytex's shareholders and potential investors with information regarding Baytex, including management's assessment
of Baytex's future plans and operations, certain statements in this report are "forward-looking statements" within the meaning of the United States
Private Securities Litigation Reform Act of 1995 and "forward-looking information" within the meaning of applicable Canadian securities legislation
(collectively, "forward-looking statements"). In some cases, forward-looking statements can be identified by terminology such as "believe",
"continue", ""estimate", "expect", "forecast", "intend", "may", "objective", "ongoing", "outlook", "potential", "project", "plan", "should", "target",
"would", "will" or similar words suggesting future outcomes, events or performance. The forward-looking statements contained in this report speak
only as of the date thereof and are expressly qualified by this cautionary statement.
Specifically, this report contains forward-looking statements relating to but not limited to: our business strategies, plans and objectives; that we are
on track to deliver $250 million ($0.45 per basic share) of free cash flow in 2021, are building operational momentum and executing our plan to
maximize free cash flow and accelerate our debt reduction strategy; in 2021 that: we will benefit from a disciplined approach to capital allocation
and a continued drive to improve our cost structure and capital efficiencies, our high graded capital program is focused on high netback light oil
assets in the Viking and Eagle Ford and that, at current commodity prices, we intend to implement a heavy oil program in the second half of the
year; our guidance for 2021 exploration and development expenditures, production, royalty rate, operating, transportation, general and
administration and interest expense and leasing expenditures and asset retirement obligations; that 48% of our net crude oil exposure for 2021 is
hedged; In 2021, we expect to benefit from our diversified oil weighted portfolio and our commitment to allocate capital effectively and that our
priority is to generate stable production, maximize free cash flow and further strengthen our balance sheet; for 2021 in the Eagle Ford: we expect
to bring wells drilled in Q4/2020 on stream in Q1/2021 and bring 18 net wells on production; in the Viking: that we expect to bring 43 net wells on
stream in Q1/2020 and 120 net wells on stream in 2021; we have minimal heavy oil development scheduled in H1/2021 and, at current commodity
prices, we intend to implement a drilling program in H2/2021 with upwards of 30 net wells drilled at Lloydminster and 6 net wells drilled at Peace
River; in Pembina Duvernay we have flexibility to drill up to 4 net wells in H2/2021; based on the forward strip, we expect to increase our financial
liquidity to approximately $500 million in 2021; that we use financial derivative contracts and crude-by-rail to reduce adjusted funds flow volatility
and the percentage of our expected production in 2021 of Canadian light oil and heavy oil for which we have hedged the differential to WTI; our
2025 GHG emissions intensity reduction target and our strategy to reach the target; that we plan to publish our fifth corporate sustainability report
this year; future development costs, F&D and FD&A; our reserves life index; forecast prices for oil and natural gas; forecast inflation and exchange
rates; the net present value before income taxes of the future net revenue attributable to our reserves; the value of our undeveloped land holdings
and our estimated net asset value. In addition, information and statements relating to reserves are deemed to be forward-looking statements, as
they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or
estimated, and that they can be profitably produced in the future.
These forward-looking statements are based on certain key assumptions regarding, among other things: petroleum and natural gas prices and
differentials between light, medium and heavy oil prices; well production rates and reserve volumes; our ability to add production and reserves
through our exploration and development activities; capital expenditure levels; our ability to borrow under our credit agreements; the receipt, in a
timely manner, of regulatory and other required approvals for our operating activities; the availability and cost of labour and other industry services;
interest and foreign exchange rates; the continuance of existing and, in certain circumstances, proposed tax and royalty regimes; our ability to
develop our crude oil and natural gas properties in the manner currently contemplated; and current industry conditions, laws and regulations
continuing in effect (or, where changes are proposed, such changes being adopted as anticipated). Readers are cautioned that such assumptions,
although considered reasonable by Baytex at the time of preparation, may prove to be incorrect.
Actual results achieved will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and
other factors. Such factors include, but are not limited to: the volatility of oil and natural gas prices and price differentials (including the impacts of
Covid-19); the availability and cost of capital or borrowing; risks associated with our ability to exploit our properties and add reserves; availability
and cost of gathering, processing and pipeline systems; that our credit facilities may not provide sufficient liquidity or may not be renewed; failure
to comply with the covenants in our debt agreements; risks associated with a third-party operating our Eagle Ford properties; public perception
and its influence on the regulatory regime; restrictions or costs imposed by climate change initiatives and the physical risks of climate change; new
regulations on hydraulic fracturing; restrictions on or access to water or other fluids; changes in government regulations that affect the oil and gas
industry; regulations regarding the disposal of fluids; changes in environmental, health and safety regulations; costs to develop and operate our
properties; variations in interest rates and foreign exchange rates; risks associated with our hedging activities; retaining or replacing our leadership
and key personnel; changes in income tax or other laws or government incentive programs; uncertainties associated with estimating oil and natural
gas reserves; our inability to fully insure against all risks; risks of counterparty default; risks related to our thermal heavy oil projects; alternatives
to and changing demand for petroleum products; risks associated with our use of information technology systems; results of litigation; risks
associated with large projects; risks associated with the ownership of our securities, including changes in market-based factors; risks for United
States and other non-resident shareholders, including the ability to enforce civil remedies, differing practices for reporting reserves and production,
additional taxation applicable to non-residents and foreign exchange risk; and other factors, many of which are beyond our control.
These and additional risk factors are discussed in our Annual Information Form, Annual Report on Form 40-F and Management's Discussion and
Analysis for the year ended December 31, 2020, to be filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange
Commission not later than March 31, 2021 and in our other public filings
The above summary of assumptions and risks related to forward-looking statements has been provided in order to provide shareholders and
potential investors with a more complete perspective on Baytex’s current and future operations and such information may not be appropriate for
other purposes.
There is no representation by Baytex that actual results achieved will be the same in whole or in part as those referenced in the forward-looking
statements and Baytex does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether
as a result of new information, future events or otherwise, except as may be required by applicable securities law.
All amounts in this report are stated in Canadian dollars unless otherwise specified.
Baytex Energy Corp. 2020 Annual Report
3
Non-GAAP Financial and Capital Management Measures
In this report, we refer to certain financial measures (such as adjusted funds flow, exploration and development expenditures, free cash flow, net
debt and operating netback) which do not have any standardized meaning prescribed by Canadian GAAP (“non-GAAP measures”) and are
considered non-GAAP measures. While adjusted funds flow, exploration and development expenditures, free cash flow, net debt and operating
netback are commonly used in the oil and gas industry, our determination of these measures may not be comparable with calculations of similar
measures for other issuers.
Adjusted funds flow is not a measurement based on generally accepted accounting principles ("GAAP") in Canada, but is a financial term commonly
used in the oil and gas industry. We define adjusted funds flow as cash flow from operating activities adjusted for changes in non-cash operating
working capital and asset retirement obligations settled. Our determination of adjusted funds flow may not be comparable to other issuers. We
consider adjusted funds flow a key measure that provides a more complete understanding of operating performance and our ability to generate
funds for exploration and development expenditures, debt repayment, settlement of our abandonment obligations and potential future dividends.
In addition, we use a ratio of net debt to adjusted funds flow to manage our capital structure. We eliminate settlements of abandonment obligations
from cash flow from operations as the amounts can be discretionary and may vary from period to period depending on our capital programs and
the maturity of our operating areas. The settlement of abandonment obligations are managed with our capital budgeting process which considers
available adjusted funds flow. Changes in non-cash working capital are eliminated in the determination of adjusted funds flow as the timing of
collection, payment and incurrence is variable and by excluding them from the calculation we are able to provide a more meaningful measure of
our cash flow on a continuing basis. For a reconciliation of adjusted funds flow to cash flow from operating activities, see Management's Discussion
and Analysis of the operating and financial results for the year ended December 31, 2020.
Exploration and development expenditures is not a measurement based on GAAP in Canada. We define exploration and development
expenditures as additions to exploration and evaluation assets combined with additions to oil and gas properties. Our definition of exploration and
development expenditures may not be comparable to other issuers. We use exploration and development expenditures to measure and evaluate
the performance of our capital programs. The total amount of exploration and development expenditures is managed as part of our budgeting
process and can vary from period to period depending on the availability of adjusted funds flow and other sources of liquidity.
Free cash flow is not a measurement based on GAAP in Canada. We define free cash flow as adjusted funds flow less exploration and development
expenditures (both non-GAAP measures discussed above), payments on lease obligations, and asset retirement obligations settled. Our
determination of free cash flow may not be comparable to other issuers. We use free cash flow to evaluate funds available for debt repayment,
common share repurchases, potential future dividends and acquisition and disposition opportunities.
Net debt is not a measurement based on GAAP in Canada. We define net debt to be the sum of cash, trade and other accounts receivable, trade
and other accounts payable, and the principal amount of both the long-term notes and the credit facilities. Our definition of net debt may not be
comparable to other issuers. We believe that this measure assists in providing a more complete understanding of our cash liabilities and provides
a key measure to assess our liquidity. We use the principal amounts of the credit facilities and long-term notes outstanding in the calculation of net
debt as these amounts represent our ultimate repayment obligation at maturity. The carrying amount of debt issue costs associated with the credit
facilities and long-term notes is excluded on the basis that these amounts have already been paid by Baytex at inception of the contract and do
not represent an additional source of capital or repayment obligation.
Operating netback is not a measurement based on GAAP in Canada, but is a financial term commonly used in the oil and gas industry. Operating
netback is equal to petroleum and natural gas sales less blending expense, royalties, production and operating expense and transportation
expense divided by barrels of oil equivalent sales volume for the applicable period. Our determination of operating netback may not be comparable
with the calculation of similar measures for other entities. We believe that this measure assists in characterizing our ability to generate cash margin
on a unit of production basis and is a key measure used to evaluate our operating performance.
4
Baytex Energy Corp. 2020 Annual Report
MESSAGE TO SHAREHOLDERS
In one of the most challenging years experienced by our industry, we delivered on our commitment to preserve
financial liquidity, capture cost savings and generate free cash flow. The Covid-19 pandemic required a dynamic
response to the oil price collapse and our team delivered. We re-set our business in the face of extremely volatile
crude oil markets and intensified efforts to improve all aspects of our cost structure and capital efficiencies, while
protecting the health and safety of our personnel. We are now benefiting from these actions as we are poised to
generate meaningful free cash flow in 2021 and continue our de-leveraging strategy.
In 2020, we reduced our capital budget by 50% and identified cost savings of approximately $100 million.
We produced 79,781 boe/d (82% liquids) with capital expenditures of $280 million, in line with our annual
guidance. We also hit all of our cost targets with operating expenses averaging $11.35/boe, transportation expenses
of $0.97/boe and general and administrative expenses under $1.20/boe.
We generated free cash flow of $18 million and a $24 million net debt reduction (including the Canadian dollar
strengthening relative to the U.S. dollar). We also negotiated a bank credit facility extension and refinanced our
long-term notes, both important measures to ensure our financial liquidity. We issued US$500 million senior
unsecured notes maturing April 2027 which enabled us to redeem two near term notes maturing in 2021 and
2022. As of December 31, 2020, we held $367 million of undrawn capacity on our credit facilities, resulting in
liquidity, net of working capital, of $319 million. We are well within our financial covenants and our first long-term
note maturity of US$400 million is not until June 2024.
In addition, we continue to build on our long term, high quality and diversified oil portfolio. Our operating teams are
well established with a track record of enhancing our inventory and delivering results. Our proved plus probable
reserves at year-end total 462 mmboe and we maintain a strong reserves life index of 17.9 years. In Canada, we
have one of the largest conventional oil portfolios, including high operating netback, light oil production in the
Viking and low decline, heavy oil production at Peace River and Lloydminster. We also hold a dominant land
position in the emerging light oil resource play in the Pembina Duvernay, which has similar geologic and reservoir
characteristics to our Eagle Ford shale asset in the United States. Our position in the Eagle Ford is defined by one
of the highest quality, lowest-cost U.S. resource plays with outstanding drilling economics.
As part of our core values, we are driven to safely and responsibly develop energy resources while reducing
environmental impact. In 2019, we established a GHG emissions reduction target. Our objective was to reduce our
corporate GHG emission intensity (tonnes of CO2e per boe) by 30% by 2021, relative to our 2018 baseline. We are
pleased to announce that we have exceeded this target, achieving a 46% reduction in our GHG emissions intensity
through year-end 2020. This represents an annual reduction of 1.6 million tonnes of CO2e and is equivalent to
taking 340,000 cars off the road annually.
As an element of our corporate culture we continue to set the bar higher. We have established a new target to
reduce our corporate GHG emission intensity by a further 33% from current levels by 2025. This equates to an
approximate 65% reduction by 2025, relative to our 2018 baseline. The entire organization is proud of our emissions
reduction strategy which includes gas conservation and combustion, reusing associated gas as fuel for field
activities, reduced emissions from storage tanks, along with monitoring and preventing fugitive emissions.
We look forward to publishing our fifth corporate sustainability report later this year. We are committed to
transparency and accountability, as well as progressing the environmental and social aspects of our business.
Baytex Energy Corp. 2020 Annual Report
5
Looking Forward
We maintain an attractive and deep inventory of development drilling locations with approximately ten years or
more in each of our core assets. In 2021, we will benefit from a disciplined approach to capital allocation as well as
our continued drive to improve our cost structure and capital efficiencies. Our high graded capital program is focused
largely on our high netback light oil assets in the Viking and Eagle Ford. At current commodity prices, we intend to
implement a heavy oil program in the second half of the year.
We are executing our plan to maximize free cash flow and accelerate our debt reduction strategy. Our 2021
guidance remains unchanged as we target production of 73,000 to 77,000 boe/d with exploration and development
expenditures of $225 to $275 million. During Q4/2020, we resumed drilling activity, which is leading to operational
momentum early in 2021 with current production over 78,000 boe/d. At the time of writing, we expect to generate
over $250 million ($0.45 per basic share) of free cash flow in 2021 and increase our financial liquidity to over $550
million.
We maintain a consistent approach to risk management and marketing, utilizing various financial derivative
contracts and crude-by-rail to reduce the volatility in our adjusted funds flow. For 2021, we have entered into hedges
on approximately 48% of our net crude oil exposure, largely utilizing a 3-way option structure that provides WTI
price protection at US$45/bbl with upside participation to US$52/bbl. We are also contracted to deliver 5,500 bbl/d
of our heavy oil volumes to market by rail.
We continue to enhance our organizational capability at all levels - from the Board, to management and to all
employees. I am particularly proud of our response to the Covid-19 pandemic as we strive to create a more
sustainable business and prosperous future. Our team is resilient and focused and we are totally committed
to generating value for shareholders.
We look forward to executing our plans for the benefit of all stakeholders and we thank you for your support.
Sincerely,
Edward D. LaFehr
President and Chief Executive Officer
February 24, 2021
6
Baytex Energy Corp. 2020 Annual Report
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following is management’s discussion and analysis (“MD&A”) of the operating and financial results of Baytex Energy Corp. for
the years ended December 31, 2020 and 2019. This information is provided as of February 24, 2021. In this MD&A, references to
“Baytex”, the “Company”, “we”, “us” and “our” and similar terms refer to Baytex Energy Corp. and its subsidiaries on a consolidated
basis, except where the context requires otherwise. The results for the three months and year ended December 31, 2020
("Q4/2020" and "2020") have been compared with the results for the three months and year ended December 31, 2019 ("Q4/2019"
and "2019"). This MD&A should be read in conjunction with the Company’s audited consolidated financial statements
(“consolidated financial statements”) for the years ended December 31, 2020 and 2019, together with the accompanying notes and
the Annual Information Form for the year ended December 31, 2020. These documents and additional information about Baytex
are accessible on the SEDAR website at www.sedar.com and through the U.S. Securities and Exchange Commission at
www.sec.gov. All amounts are in Canadian dollars, unless otherwise stated, and all tabular amounts are in thousands of Canadian
dollars, except for percentages and per common share amounts or as otherwise noted.
In this MD&A, barrel of oil equivalent (“boe”) amounts have been calculated using a conversion rate of six thousand cubic feet of
natural gas to one barrel of oil, which represents an energy equivalency conversion method applicable at the burner tip and does
not represent a value equivalency at the wellhead. While it is useful for comparative measures, it may not accurately reflect
individual product values and may be misleading if used in isolation.
This MD&A contains forward-looking information and statements along with certain measures which do not have any standardized
meaning prescribed by Canadian Generally Accepted Accounting Principles ("GAAP"). The terms "adjusted funds flow", "operating
netback", "exploration and development expenditures", "free cash flow", "net debt", and "Bank EBITDA" do not have any
standardized meaning as prescribed by GAAP and therefore may not be comparable to similar measures presented by other
companies where similar terminology is used. We refer you to our advisory on forward-looking information and statements and a
summary of our non-GAAP measures at the end of the MD&A.
BAYTEX ENERGY CORP.
Baytex Energy Corp. is a North American focused oil and gas company based in Calgary, Alberta. The company operates in
Canada and the United States ("U.S"). The Canadian operating segment includes our light oil assets in the Viking and Duvernay,
our heavy oil assets in Peace River and Lloydminster and our conventional oil and natural gas assets in Western Canada. The U.S.
operating segment includes our Eagle Ford assets in Texas.
CURRENT ENVIRONMENT
In March 2020, the World Health Organization declared a global pandemic related to the novel coronavirus ("COVID-19"). The
emergence of COVID-19 and the steps taken by governments to control the spread of the virus resulted in significant instability in
the global economy and a sharp decline in demand for crude oil. This combined with the increased supply of crude oil due to the
Russia and Saudi Arabia price war resulted in an unprecedented collapse in global crude oil prices and significant volatility during
Q2/2020. Global crude oil prices began to recover during the second half of 2020 as Russia and members of OPEC (collectively,
"OPEC+") agreed to curtail production and governments began to ease restrictions which increased demand. In Q4/2020 vaccines
were approved and distribution began which fueled further optimism that demand will be restored. Vaccine approval and
distribution has continued in 2021 and OPEC+ has agreed to continue production curtailments which has resulted in recent
improvements in crude oil prices in 2021.
During 2020, we took significant action in response to COVID-19 and the uncertain outlook for our industry. We preserved our
financial liquidity by reducing exploration and development expenditures, limiting discretionary spending and shutting-in low margin
production when operating netbacks were challenged. As a result 2020 production and capital spending were lower than 2019.
Despite lower production and volatile commodity prices we generated free cash flow of $18.1 million during 2020 which reflects the
success of our cost savings initiatives and the disciplined execution of our capital programs. We also maintained $367.2 million of
availability on our credit facilities at December 31, 2020.
Baytex Energy Corp. 2020 Annual Report
7
2020 ANNUAL HIGHLIGHTS
Our financial and operating results for 2020 reflect the challenging market conditions caused by the COVID-19 pandemic. Q1/2020
included an active capital program with commodity prices remaining fairly consistent with 2019, however capital spending was
suspended during Q2/2020 as prices collapsed and we focused on reducing costs and preserving our liquidity. We initiated a
targeted restart of development activity on our light oil properties in the U.S. and Canada as prices stabilized and the economic
outlook improved during the second half of 2020. Exploration and development expenditures of $280.3 million were approximately
half of the original budget which resulted in production of 79,781 boe/d for 2020. Despite the volatile commodity prices we were
able to generate $18.1 million of free cash flow during 2020 which reflects our focus on cost savings along with the disciplined
execution of our capital programs in the U.S. and Canada.
In Q1/2020, we issued US$500 million principal amount of senior unsecured notes. We used the proceeds from the issuance and
availability on our credit facilities to redeem the US$400 million principal amount of senior unsecured notes due in 2021 and the
$300 million principal amount of senior unsecured notes due in 2022. In addition, we extended the maturity on our credit facilities to
April 2, 2024. As a result of these actions, we do not have any debt maturities until 2024 and we had $367.2 million available on our
credit facilities at December 31, 2020.
In Canada, production of 48,602 boe/d for 2020 was consistent with expectations after we adjusted development expenditures in
response to volatile commodity prices. We were active on our Viking light oil and heavy oil properties during Q1/2020 as the
outlook for Canadian oil prices was stable early in the year. After Q1/2020 Canadian development was limited until Q4/2020 when
we initiated completions activity on two (2.0 net) light oil wells in the Duvernay and began development of two (2.0 net) wells on our
conventional properties as the outlook for light oil and natural gas prices continued to improve. Total exploration and development
expenditures of $175.0 million for 2020 included costs associated with drilling 102 (99.2 net) light oil wells in the Viking, 2 (2.0 net)
light oil wells in the Duvernay, 33 (33.0 net) heavy oil wells, and 2 (2.0 net) natural gas wells.
In the U.S., we invested $105.4 million on exploration and development activity during 2020 and drilled 65 (16.3 net) wells and
initiated production from 62 (14.1 net) wells. Production of 31,179 boe/d was consistent with expectations and reflects moderated
completion activity on our Eagle Ford properties during Q2/2020 after the sharp decline in crude oil prices. Activity was restarted
during Q3/2020 and was maintained leading into 2021 as the outlook for oil prices improved.
Global benchmark prices for crude oil were volatile during 2020. After a sharp decline in March 2020, oil prices stabilized in the
second half of 2020 due to renewed production curtailments by OPEC+ along with improved demand after governments eased
restrictions intended to limit the spread of COVID-19. Even with recent improvements, the WTI benchmark price was 31% lower in
2020 relative to 2019 due to elevated global inventory levels and lower demand caused by the COVID-19 pandemic. The WTI
benchmark price averaged US$39.40/bbl for 2020 compared to US$57.03/bbl for 2019.
Adjusted funds flow was $311.5 million for 2020 compared to $902.4 million for 2019. Our financial and operating results for 2020
reflect our reduced development activity during a period of low oil prices. Lower crude oil prices were the main factor that lead to a
$571.6 million decrease in operating netback relative to 2019. We remained focused on our cost savings initiatives, which resulted
in a $93.1 million decrease in operating, transportation, and general and administrative expenses for 2020 compared to 2019. Our
net loss of $2.4 billion for 2020 compared to $12.5 million in 2019 reflects impairments of $2.4 billion recorded in 2020 due to the
sharp decline in forecasted commodity prices.
Net debt was $1.85 billion at December 31, 2020 which is consistent with $1.87 billion at December 31, 2019. Net debt was
reduced with $18.1 million of free cash flow for 2020 along with a $22.4 million decrease in the reported amount of our U.S. dollar
denominated public debt due to the strengthening of the Canadian dollar at December 31, 2020 relative to December 31, 2019.
These decreases were partially offset by total transaction and financing costs of $17.6 million related to the refinancing transactions
in Q1/2020 resulting in the $24.2 million decrease in net debt in 2020 compared to 2019. We had $367.2 million available on our
credit facilities at December 31, 2020.
8
Baytex Energy Corp. 2020 Annual Report
GUIDANCE
The following table compares our 2020 annual guidance to our 2020 results. We delivered production that was consistent with our
annual guidance while exploration and development expenditures approximated the mid-point of our guidance range. Expenses,
lease expenditures, and settlement of asset retirement obligations were within or slightly below our annual guidance due to our
continued efforts to control costs during a period of volatile oil prices.
Exploration and development expenditures ($ millions)
$500 - $575
$260 - $290
Original Annual
Guidance (1)
Revised Annual
Guidance (2)
Production (boe/d)
Expenses:
Royalty rate (%)
Operating ($/boe)
Transportation ($/boe)
93,000 - 97,000
78,000 - 82,000
18.0 - 18.5
18.5
$11.25 - $12.00
$11.75 - $12.50
$1.20 - $1.30
$0.95 - $1.05
2020 Results
$280.3
79,781
17.7
$11.35
$0.97
General and administrative ($ millions)
$45 ($1.30/boe)
$38 ($1.30/boe)
$34.3 ($1.17/boe)
Interest ($ millions)
$112 ($3.23/boe)
$112 ($3.84/boe)
$106.5 ($3.65/boe)
Leasing expenditures ($ millions)
Asset retirement obligations ($ millions)
(1) As announced on December 4, 2019.
(2) As announced on June 25, 2020.
$7
$19
$7
$10
$6
$7
On December 2, 2020 our Board of Directors approved our 2021 capital budget of $225 - $275 million which is designed to
generate production of 73,000 - 77,000 boe/d. The program is expected to be equally weighted between the first and second half of
2021 and we will maintain operational flexibility to adjust spending in response to commodity prices.
The following table summarizes our 2021 annual guidance as released on December 2, 2020.
Exploration and development expenditures ($ millions)
Production (boe/d)
Expenses:
Royalty rate (%)
Operating ($/boe)
Transportation ($/boe)
General and administrative ($ millions)
Interest ($ millions)
Leasing expenditures ($ millions)
Asset retirement obligations ($ millions)
2021 Guidance
$225 - $275
73,000 - 77,000
18.0 - 18.5
$11.50 - $12.25
$1.00 - $1.10
$42 ($1.53/boe)
$105 ($3.84/boe)
$4
$6
Baytex Energy Corp. 2020 Annual Report
9
RESULTS OF OPERATIONS
The Canadian operating segment includes our light oil assets in Viking and Duvernay, our heavy oil assets in Peace River and
Lloydminster and our conventional oil and natural gas assets in Western Canada. The U.S. operating segment includes our Eagle
Ford assets in Texas.
Production
Daily Production
Liquids (bbl/d)
Light oil and condensate
Heavy oil
Natural Gas Liquids ("NGL")
Total liquids (bbl/d)
Natural gas (mcf/d)
Total production (boe/d)
Production Mix
Segment as a percent of total
Light oil and condensate
Heavy oil
NGL
Natural gas
Years Ended December 31
2020
2019
Canada
U.S.
Total
Canada
U.S.
Total
19,103
21,142
1,224
41,469
42,799
48,602
17,953
—
6,116
24,069
42,665
31,179
37,056
21,142
7,340
65,538
85,464
79,781
22,358
26,741
1,364
50,463
48,969
58,625
21,229
—
8,865
30,094
53,773
39,055
43,587
26,741
10,229
80,557
102,742
97,680
61 %
39 %
100 %
60 %
40 %
100 %
39 %
44 %
3 %
14 %
58 %
— %
20 %
22 %
46 %
27 %
9 %
18 %
38 %
46 %
2 %
14 %
54 %
— %
23 %
23 %
45 %
27 %
10 %
18 %
Production was 79,781 boe/d in 2020 compared to 97,680 boe/d in 2019. Our production results for 2020 were lower relative to
2019 as a result of lower development activity in Canada and the U.S. following the sharp decline in crude oil prices in March 2020.
In Canada, production was 48,602 boe/d in 2020 compared to 58,625 boe/d in 2019. Lower production in 2020 is the result of lower
development activity relative to 2019 in addition to temporarily shutting-in production in response to the sharp decline in crude oil
prices in March 2020. We brought production back online as prices improved in June 2020 and restarted our development
programs as the outlook for oil and natural gas prices improved during Q4/2020.
Production in the U.S. was 31,179 boe/d in 2020 compared to 39,055 boe/d for 2019. Lower production is the result of lower
completion activity relative to 2019 as drilling and completion activity was suspended during Q2/2020 and moderated for the
remainder of 2020. During 2020 we initiated production from 62 (14.1 net) wells compared to 109 (25.1 net) wells during 2019.
Annual production of 79,781 boe/d for 2020 was in line with expectations and within our annual guidance range of 78,000 - 82,000
boe/d. We expect to sustain production of 73,000 - 77,000 boe/d in 2021 with an objective to maximize free cash flow.
Commodity Prices
The prices received for our crude oil and natural gas production directly impact our earnings, adjusted funds flow and our financial
position.
Crude Oil
Global benchmark prices for crude oil were relatively strong leading into 2020 due to a stable outlook for supply and demand.
Benchmark prices declined rapidly in March after members of the OPEC+ group began to increase the supply of crude oil to the
global market and measures to limit the spread of COVID-19 resulted in a significant decrease in the demand for crude-oil. Global
benchmark prices began to improve in July 2020 following the OPEC+ decision to reinstate supply cuts, combined with improved
demand after measures intended to limit the spread of COVID-19 were relaxed. Despite the increasing presence of a second wave
of COVID-19, prices further improved in Q4/2020 after the first of several vaccines was approved and optimism about the
resumption of economic activity improved. Even with the WTI benchmark price increasing in Q4/2020, the benchmark was lower
during 2020 and averaged US$39.40/bbl compared to US$57.03/bbl during 2019.
10
Baytex Energy Corp. 2020 Annual Report
We compare the price received for our U.S. crude oil production to the Magellan East Houston ("MEH") stream at Houston, Texas
which is a representative benchmark for light oil pricing at the U.S. Gulf coast. The MEH benchmark averaged US$40.15/bbl during
2020, representing a premium of US$0.75/bbl relative to WTI, compared to US$61.98/bbl or a premium of US$4.95/bbl for 2019.
The decrease in the MEH benchmark premium to WTI in 2020 was a result of elevated inventory levels and lower refinery demand
on the U.S. Gulf coast relative to 2019.
Prices for Canadian oil trade at a discount to WTI due to a lack of egress to diversified markets from Western Canada. Canadian
light and heavy oil differentials to WTI were wider in early 2020 relative to 2019 as a result of higher Canadian oil production
leading into the year. During Q1/2020, the Edmonton par discount to WTI was US$7.92/bbl and the WCS differential was
US$20.53/bbl. Canadian oil differentials began to narrow due to production shut-ins in Western Canada during Q2/2020. This
resulted in an Edmonton par differential of US$5.60/bbl and a WCS differential of US$12.60/bbl for 2020 which was relatively
consistent with US$4.86/bbl and US$12.75/bbl for 2019, respectively.
We compare the price received for our light oil production in Canada to the Edmonton par benchmark oil price which is the
representative benchmark for light grades of crude oil in Western Canada. The Edmonton par price averaged $45.34/bbl for 2020
compared to $69.22/bbl for 2019. Edmonton par traded at a discount to WTI of US$5.60/bbl in 2020 which is relatively consistent
with US$4.86/bbl for 2019.
The price received for our heavy oil production in Canada is based on the WCS benchmark price which is the representative
benchmark for heavy grades of crude oil in Western Canada. The WCS heavy oil price for 2020 averaged $35.95/bbl, which
represents a differential of US$12.60/bbl to WTI, compared to $58.75/bbl for 2019, which represents a differential of US$12.75/bbl.
Natural Gas
U.S. natural gas prices for 2020 were lower than 2019 as U.S. natural gas inventory levels remained elevated due to lower demand
despite falling natural gas production. Canadian natural gas prices improved during 2020 due to low Alberta inventory levels along
with improved demand in Western Canada and high utilization of pipeline export capacity during 2020.
Our U.S. natural gas production is priced in reference to the New York Mercantile Exchange ("NYMEX") natural gas index. The
NYMEX natural gas benchmark averaged US$2.08/mmbtu in 2020 which is lower than US$2.63/mmbtu in 2019. Record U.S.
natural gas production levels leading in to 2020 resulted in an oversupplied North American market and lower natural gas prices in
2020 relative to 2019.
In Canada, we receive natural gas pricing based on the AECO benchmark which continues to trade at a discount to NYMEX as a
result of limited market access for Canadian natural gas production. The AECO benchmark averaged $2.24/mcf during 2020
compared to $1.62/mcf during 2019. The AECO benchmark was higher in 2020 relative to 2019 due to lower associated gas
production from lower oil production in Western Canada during 2020.
The following tables compare select benchmark prices and our average realized selling prices for the years ended December 31,
2020 and 2019.
Benchmark Averages
WTI oil (US$/bbl) (1)
MEH oil (US$/bbl) (2)
MEH oil differential to WTI (US$/bbl)
Edmonton par oil ($/bbl) (3)
Edmonton par oil differential to WTI (US$/bbl)
WCS heavy oil ($/bbl) (4)
WCS heavy oil differential to WTI (US$/bbl)
AECO natural gas price ($/mcf) (5)
NYMEX natural gas price (US$/mmbtu) (6)
CAD/USD average exchange rate
Years Ended December 31
2020
39.40
40.15
0.75
45.34
(5.60)
35.95
(12.60)
2.24
2.08
1.3413
2019
Change
57.03
61.98
4.95
69.22
(4.86)
58.75
(12.75)
1.62
2.63
1.3269
(17.63)
(21.83)
(4.20)
(23.88)
(0.74)
(22.80)
0.15
0.62
(0.55)
0.0144
(1) WTI refers to the arithmetic average of NYMEX prompt month WTI for the applicable period.
(2) MEH refers to arithmetic average of the Argus WTI Houston differential weighted index price for the applicable period.
(3) Edmonton par refers to the average posting price for the benchmark MSW crude oil.
(4) WCS refers to the average posting price for the benchmark WCS heavy oil.
(5) AECO refers to the AECO arithmetic average month-ahead index price published by the Canadian Gas Price Reporter ("CGPR").
(6) NYMEX refers to the NYMEX last day average index price as published by the CGPR.
Baytex Energy Corp. 2020 Annual Report
11
Average Realized Sales Prices
Light oil and condensate ($/bbl)
Heavy oil ($/bbl) (1)
NGL ($/bbl)
Natural gas ($/mcf)
Weighted average ($/boe) (1)
Years Ended December 31
2020
2019
Canada
U.S.
Total
Canada
U.S.
Total
$
42.35 $
49.84 $
45.98 $
65.99 $
77.46 $
24.28
13.47
2.13
—
15.57
2.65
24.28
15.22
2.39
44.20
16.93
1.71
—
18.74
3.43
71.57
44.20
18.50
2.61
$
29.42 $
35.38 $
31.75 $
47.15 $
51.08 $
48.72
(1) Realized heavy oil prices are calculated based on sales volumes and sales dollars, net of blending and other expense.
Average Realized Sales Prices
Our weighted average sales price was $31.75/boe for 2020 compared to $48.72/boe for 2019. Our realized price in the U.S. was
$35.38/boe in 2020 which is $15.70/boe lower than $51.08/boe in 2019. In Canada, our realized price of $29.42/boe for 2020 was
$17.73/boe lower than $47.15/boe for 2019. The decrease in our realized price in Canada and the U.S. for 2020 was a result of the
decrease in North American benchmark prices relative to 2019.
We compare our light oil realized price in Canada to the Edmonton par benchmark price. Our realized light oil and condensate
price in 2020 was $42.35/bbl representing a discount of $2.99/bbl to the Edmonton par benchmark which is relatively consistent
with 2019 when our realized price was $65.99/bbl or a discount of $3.23/bbl. The $23.64/boe decrease in our realized light oil
pricing in 2020 was driven by the $23.88/boe decline in the Edmonton par benchmark relative to 2019.
We compare the price received for our U.S. light oil and condensate production to the MEH benchmark. Our realized light oil and
condensate price averaged $49.84/bbl for 2020 compared to $77.46/bbl for 2019. Expressed in U.S. dollars, our realized light oil
and condensate price of US$37.16/bbl for 2020 reflects a US$2.99/bbl discount to the MEH benchmark for 2020 compared to a
realized price of US$58.38/bbl and discount of US$3.60/bbl in 2019. A change in marketing contracts during Q3/2019 resulted in
improved price realizations for 2020 relative to 2019 which partially offset the impact of a US$21.83/bbl decrease in the MEH
benchmark price over the same period.
Our realized heavy oil price, net of blending and other expense averaged $24.28/bbl in 2020 compared to $44.20/bbl in 2019. Our
realized heavy oil price for 2020 decreased $19.92/bbl compared to a $22.80/bbl decrease in the WCS benchmark. Our realized
heavy oil price did not decrease as much as the WCS benchmark as we shut-in certain properties with lower quality production
during 2020 which resulted in improved price realizations during the year.
Our realized NGL price as a percentage of WTI can vary from period to period based on the product mix of our NGL volumes and
changes in the market prices of the underlying products. Our realized NGL price was $15.22/bbl in 2020 or 29% of WTI (expressed
in Canadian dollars) compared to $18.50/bbl or 24% of WTI (expressed in Canadian dollars) in 2019. Our realized NGL price was
higher as a percentage of WTI in 2020 relative to 2019 as the decrease in the underlying products was not as large relative to the
decrease in WTI over the same periods.
We compare our realized natural gas price in Canada to the AECO benchmark price. Our realized natural gas price for 2020 was
$2.13/mcf compared to $1.71/mcf in 2019. The increase in our realized natural gas price in Canada during 2020 compared to 2019
is consistent with the increase in the AECO natural gas price in 2020. In the U.S., our realized natural gas price was US$1.98/mcf
for 2020 compared to US$2.58/mcf in 2019. The decrease in our realized natural gas price in the U.S. during 2020 is consistent
with the US$0.55/mmbtu decrease in the NYMEX benchmark in 2020 compared to 2019.
12
Baytex Energy Corp. 2020 Annual Report
Petroleum and Natural Gas Sales
($ thousands)
Oil sales
Years Ended December 31
2020
2019
Canada
U.S.
Total
Canada
U.S.
Total
Light oil and condensate
$ 296,125 $ 327,460 $ 623,585 $ 538,487 $ 600,163 $ 1,138,650
Heavy oil
NGL
Total liquids sales
Natural gas sales
236,235
—
236,235
500,187
—
500,187
6,037
34,845
40,882
8,430
60,647
69,077
538,397
362,305
900,702
1,047,104
660,810
1,707,914
33,344
41,431
74,775
30,620
67,385
98,005
Total petroleum and natural gas sales
571,741
403,736
975,477
1,077,724
728,195
1,805,919
Blending and other expense
(48,381)
—
(48,381)
(68,795)
—
(68,795)
Total sales, net of blending and other expense
$ 523,360 $ 403,736 $ 927,096 $ 1,008,929 $ 728,195 $ 1,737,124
Total sales, net of blending and other expense, of $927.1 million for 2020 decreased $810.0 million from $1,737.1 million for 2019.
The decrease in total sales in 2020 is a result of lower realized pricing from the decrease in benchmark pricing along with lower
production relative to 2019.
In Canada, total sales, net of blending and other expense, was $523.4 million for 2020 which is a decrease of $485.6 million from
$1,008.9 million reported for 2019. Lower pricing resulted in a $315.4 million decrease in total sales, net of blending and other
expense and lower production caused a $170.2 million decrease in total sales net of blending and other expense.
In the U.S., petroleum and natural gas sales were $403.7 million for 2020 which is a decrease of $324.5 million from $728.2 million
reported for 2019. Lower pricing in 2020 resulted in a $179.2 million decrease in total petroleum and natural gas sales while lower
production caused a $145.3 million decrease in total petroleum and natural gas sales relative to 2019.
Royalties
Royalties are paid to various government entities and to land and mineral rights owners. Royalties are calculated based on gross
revenues or on operating netbacks less capital investment for specific heavy oil projects and are generally expressed as a
percentage of total sales, net of blending and other expense. The actual royalty rates can vary for a number of reasons, including
the commodity produced, royalty contract terms, commodity price level, royalty incentives and the area or jurisdiction. The following
table summarizes our royalties and royalty rates for the years ended December 31, 2020 and 2019.
Years Ended December 31
2020
2019
($ thousands except for % and per boe)
Canada
U.S.
Total
Canada
U.S.
Total
Royalties
Average royalty rate (1)
Royalty rate per boe
$ 46,064
$ 117,671
$ 163,735
$ 107,467
$ 212,774
$ 320,241
8.8 %
29.1 %
17.7 %
10.7 %
29.2 %
18.4 %
$
2.59
$ 10.31
$
5.61
$
5.02
$ 14.93
$
8.98
(1) Average royalty rate is calculated as royalties divided by total sales, net of blending and other expense.
Royalties for 2020 were $163.7 million or 17.7% of total sales, net of blending and other expense, compared to $320.2 million or
18.4% in 2019. Total royalty expense is lower in 2020 due to lower total sales, net of blending and other expense, relative to 2019.
Our average royalty rate of 17.7% for 2020 is slightly lower than 18.4% for 2019 due to a lower royalty rate on our Canadian
properties as a result of lower commodity prices.
In Canada, royalties averaged 8.8% of sales for 2020 which was lower than 10.7% for 2019 due to lower benchmark commodity
prices which resulted in a lower royalty rate on our Canadian properties. In the U.S., royalties averaged 29.1% of sales for 2020
which is consistent with 29.2% for 2019 as the royalty rate on our U.S. production does not vary with price but can vary across our
acreage.
Our average royalty rate of 17.7% for 2020 is consistent with expectations and was slightly below our annual guidance of
approximately 18.5% for 2020. We expect our average royalty rate to be 18.0% to 18.5% in 2021.
Baytex Energy Corp. 2020 Annual Report
13
Operating Expense
Years Ended December 31
2020
2019
($ thousands except for per boe)
Operating expense
Operating expense per boe
Canada
U.S.
Total
Canada
U.S.
Total
$ 247,050 $
84,295 $ 331,345 $ 298,303 $
99,413 $ 397,716
$
13.89 $
7.39 $
11.35 $
13.94 $
6.97 $
11.16
Operating expense was $331.3 million ($11.35/boe) in 2020 compared to $397.7 million ($11.16/boe) in 2019. The decrease in total
operating expense can be attributed to a decrease in production in addition to our cost savings initiatives in 2020. The per unit
costs increased slightly to $11.35/boe in 2020 from $11.16/boe in 2019 as cost reductions did not completely offset the impact of
fixed costs on lower production volumes.
In Canada, operating expense was $247.1 million ($13.89/boe) for 2020 compared to $298.3 million ($13.94/boe) for 2019.
Operating expense in Canada decreased with lower production in 2020 compared to 2019. Despite lower production, per unit
operating expense of $13.89/boe for 2020 was consistent with $13.94/boe for 2019 due to our cost savings initiatives in addition to
shutting in certain properties with higher operating costs for a portion of 2020.
U.S. operating expense was $84.3 million ($7.39/boe) for 2020 compared to $99.4 million ($6.97/boe) for 2019. Operating expense
in the U.S. decreased with lower production in 2020 compared to 2019. Expressed in U.S. dollars, per unit operating expense was
US$5.51/boe for 2020 compared to US$5.25/boe for 2019. The slight increase in per unit operating expense in the U.S. was a
result of lower production in 2020 relative to 2019 as a portion of our operating expenses are fixed costs.
Operating expense of $11.35/boe for 2020 is consistent with our expectations and was slightly below our annual guidance range of
$11.75 - $12.50 per boe as we had higher operating cost production shut-in for a portion of 2020. We expect annual operating
expense of $11.50 - $12.25 per boe for 2021.
Transportation Expense
Transportation expense includes the costs to move production from the field to the sales point. The largest component of
transportation expense relates to the trucking of oil in Canada to pipeline and rail terminals which can vary from period to period
depending on hauling distances as we seek to optimize sales prices and trucking rates. The following table compares our
transportation expense for the years ended December 31, 2020 and 2019.
Years Ended December 31
2020
2019
($ thousands except for per boe)
Transportation expense
Transportation expense per boe
Canada
U.S.
Total
Canada
U.S.
Total
$
$
28,437 $
1.60 $
— $
— $
28,437 $
43,942 $
— $
43,942
0.97 $
2.05 $
— $
1.23
Transportation expense was $28.4 million ($0.97/boe) for 2020 compared to $43.9 million ($1.23/boe) for 2019. The decrease in
total transportation expense in 2020 relative to 2019 is primarily the result of lower light and heavy oil production in Canada.
Optimization of light and heavy oil deliveries in Canada resulted in lower per boe transportation expense for 2020 relative to 2019.
Transportation expense of $0.97/boe for 2020 is consistent with expectations and is at the low end of our annual guidance range of
$0.95 - $1.05 per boe for 2020. We expect annual transportation expense of $1.00 - $1.10 per boe for 2021.
Blending and Other Expense
Blending and other expense primarily relates to the cost of diluent purchased to reduce the viscosity of our heavy oil transported
through pipelines in order to meet pipeline specifications. The price received for the blended product is recorded as heavy oil sales
revenue. We net blending and other expense against heavy oil sales to compare the realized price on our produced volumes to
benchmark pricing.
Blending and other expense was $48.4 million for 2020 compared to $68.8 million for 2019. The reduction in blending and other
expense in 2020 compared to 2019 reflects lower heavy oil sales due to shut-in heavy oil production in addition to a lower per unit
cost of blending diluent during 2020.
14
Baytex Energy Corp. 2020 Annual Report
Financial Derivatives
As part of our normal operations, we are exposed to movements in commodity prices, foreign exchange rates and interest rates. In
an effort to manage these exposures, we utilize various financial derivative contracts which are intended to partially reduce the
volatility in our adjusted funds flow. Contracts settled in the period result in realized gains or losses based on the market price
compared to the contract price and the notional volume outstanding. Changes in the fair value of unsettled contracts are reported
as unrealized gains or losses in the period as the forward markets for commodities and currencies fluctuate and as new contracts
are executed. The following table summarizes the results of our financial derivative contracts for the years ended December 31,
2020 and 2019.
($ thousands)
Realized financial derivatives gain (loss)
Crude oil
Natural gas
Interest and financing
Total
Unrealized financial derivatives gain (loss)
Crude oil
Natural gas
Interest and financing
Equity total return swap
Total
Total financial derivatives gain (loss)
Crude oil
Natural gas
Interest and financing
Equity total return swap
Total
Years Ended December 31
2020
2019
Change
48,495 $
72,052 $
(23,557)
138
(797)
3,577
(9)
(3,439)
(788)
47,836 $
75,620 $
(27,784)
(17,696) $
(80,602) $
282
34
(1,120)
(1,857)
(358)
—
(18,500) $
(82,817) $
30,799 $
(8,550) $
420
(763)
(1,120)
29,336 $
1,720
(367)
—
(7,197) $
62,906
2,139
392
(1,120)
64,317
39,349
(1,300)
(396)
(1,120)
36,533
$
$
$
$
$
$
We recorded total financial derivatives gains of $29.3 million for 2020. The realized financial derivatives gain for 2020 of
$47.8 million was primarily a result of the market prices for crude oil settling at levels below those set in our derivative contracts.
The unrealized loss on financial derivatives of $18.5 million for 2020 was primarily due to fluctuations in future commodity prices
and the revaluation of contracts in place at December 31, 2020 compared to the value of contracts in place at the start of the year.
Realized gains on crude oil financial derivatives of $48.5 million in 2020 were primarily a result of market prices for WTI settling at
levels below the prices set in our contracts outstanding during the year.
The unrealized financial derivatives loss of $18.5 million recorded for 2020 is primarily associated with an increase in forecasted
crude oil pricing used in the valuation of WTI contracts entered during the year. The fair value of our financial derivative contracts
resulted in a net liability of $21.7 million at December 31, 2020 compared to a net liability of $3.2 million at December 31, 2019.
Baytex Energy Corp. 2020 Annual Report
15
Baytex had the following commodity financial derivative contracts as at February 24, 2021.
Period
Volume
Price/Unit (1)
Oil
Basis swap
Basis swap
Basis swap (4)
Basis swap (4)
Basis swap
Basis swap (4)
Fixed - Sell
3-way option (2)
3-way option (2)
3-way option (2)
3-way option (2)
3-way option (2)
3-way option (2)(4)
Swaption (3)
Swaption (3)
Natural Gas
Fixed - Sell
Fixed - Sell
Fixed - Sell
Fixed - Sell
3-way option (2)
3-way option (2)(4)
Jan 2021 to Jun 2021
Jan 2021 to Dec 2021
Apr 2021 to Dec 2021
Jan 2022 to Dec 2022
Jan 2021 to Dec 2021
Mar 2021 to Dec 2021
Jan 2021 to Dec 2021
Jan 2021 to Dec 2021
Jan 2021 to Dec 2021
Jan 2021 to Dec 2021
2,000 bbl/d
7,000 bbl/d
1,000 bbl/d
6,000 bbl/d
6,000 bbl/d
1,500 bbl/d
4,000 bbl/d
500 bbl/d
1,500 bbl/d
3,500 bbl/d
WTI less US$13.75/bbl
WTI less US$13.68/bbl
WTI less US$11.50/bbl
WTI less US$12.76/bbl
WTI less US$5.17/bbl
WTI less US$4.50/bbl
US$45.00/bbl
US$35.00/US$45.00/US$49.03
US$35.00/US$45.00/US$49.10
US$35.00/US$45.00/US$49.50
Jan 2021 to Dec 2021
10,000 bbl/d
US$35.00/US$45.00/US$55.00
Jan 2021 to Dec 2021
Jan 2022 to Dec 2022
Jan 2022 to Dec 2022
Jan 2022 to Dec 2022
2,000 bbl/d
1,500 bbl/d
5,000 bbl/d
5,000 bbl/d
US$37.00/US$42.50/US$48.00
US$40.00/US$50.00/US$58.10
US$53.00/bbl
US$54.00/bbl
Jan 2021 to Jun 2021
Jan 2021 to Dec 2021
Jan 2021 to Dec 2021
3,000 GJ/d
16,000 GJ/d
2,500 GJ/d
$2.71/GJ
$2.36/GJ
$2.40/GJ
Jan 2021 to Dec 2021
12,000 mmbtu/d
US$2.70/mmbtu
Jan 2022 to Dec 2022
2,500 mmbtu/d
US$2.25/US$2.75/US$3.06
Jan 2022 to Dec 2022
2,500 mmbtu/d
US$2.65/US$2.90/US$3.40
Index
WCS
WCS
WCS
WCS
MSW
MSW
WTI
WTI
WTI
WTI
WTI
WTI
WTI
WTI
WTI
AECO 7A
AECO 7A
AECO 5A
NYMEX
NYMEX
NYMEX
(1) Based on the weighted average price per unit for the period.
(2) Producer 3-way option consists of a sold put, a bought put and a sold call. To illustrate, in a US$35.00/US$45.00/US$55.00 contract, Baytex
receives WTI plus US$10.00/bbl when WTI is at or below US$35.00/bbl; Baytex receives US$45.00/bbl when WTI is between US$35.00/bbl
and US$45.00/bbl; Baytex receives the market price when WTI is between US$45.00/bbl and US$55.00/bbl; and Baytex receives US$55.00/
bbl when WTI is above US$55.00/bbl.
(3) For these contracts, the counterparty has the right, if exercised on December 31, 2021, to enter a swap transaction for the remaining term,
notional volume and fixed price per unit indicated above.
(4) Contracts entered subsequent to December 31, 2020.
16
Baytex Energy Corp. 2020 Annual Report
Operating Netback
The following table summarizes our operating netback on a per boe basis for our Canadian and U.S. operations for the years
ended December 31, 2020 and 2019.
($ per boe except for volume)
Total production (boe/d)
Operating netback:
Years Ended December 31
2020
2019
Canada
48,602
U.S.
Total
31,179
79,781
Canada
58,625
U.S.
Total
39,055
97,680
Total sales, net of blending and other expense
$
29.42 $
35.38 $
31.75 $
47.15 $
51.08 $
48.72
Less:
Royalties
Operating expense
Transportation expense
Operating netback
Realized financial derivatives gain
Operating netback after financial derivatives
(2.59)
(10.31)
(5.61)
(5.02)
(14.93)
(8.98)
(13.89)
(1.60)
(7.39)
(11.35)
—
(0.97)
(13.94)
(2.05)
(6.97)
(11.16)
—
(1.23)
11.34 $
17.68 $
13.82 $
26.14 $
29.18 $
27.35
—
—
1.64
—
—
2.12
11.34 $
17.68 $
15.46 $
26.14 $
29.18 $
29.47
$
$
Operating netback after financial derivatives was $15.46/boe for 2020 compared to $29.47/boe for 2019. Operating netback was
lower in 2020 relative to 2019 due to the decrease in benchmark pricing which resulted in a $13.60/boe reduction in sales, net of
royalties. Operating and transportation expense in Canada of $15.49/boe for 2020 reflects our production optimization and cost
savings initiatives which resulted in lower costs relative to $15.99/boe for 2019. Operating expense in the U.S. of $7.39/boe for
2020 was slightly higher relative to $6.97/boe for 2019 as a result of lower production, as a portion of our operating expense in the
U.S. are fixed costs.
General and Administrative Expense
General and administrative ("G&A") expense includes head office and corporate costs such as salaries and employee benefits,
public company costs and administrative recoveries earned for operating exploration and development activities on behalf of our
working interest partners. G&A expense fluctuates with head office staffing levels and the level of operated exploration and
development activity during the period.
The following table summarizes our G&A expense for the years ended December 31, 2020 and 2019.
($ thousands except for per boe)
Gross general and administrative expense
Overhead recoveries
General and administrative expense
General and administrative expense per boe
Years Ended December 31
2020
37,217 $
(2,949)
34,268 $
1.17 $
2019
51,660 $
(6,191)
45,469 $
1.28 $
Change
(14,443)
3,242
(11,201)
(0.11)
$
$
$
G&A expense was $34.3 million ($1.17/boe) for 2020 compared to $45.5 million ($1.28/boe) for 2019.
G&A expense of $34.3 million for 2020 was $11.2 million lower than $45.5 million for 2019 due to reduced staffing levels combined
with our cost saving initiatives, which included salary reductions and reduced consulting costs. G&A expense for 2020 includes a
benefit of $3.9 million related to the Canada Emergency Wage Subsidy ("CEWS") program implemented by the federal government
in response to the COVID-19 pandemic. Despite lower production in 2020 relative to 2019, G&A expense of $1.17/boe for 2020
was lower than $1.28/boe for 2019 as a result of our cost saving initiatives and the benefit of the CEWS.
G&A expense of $34.3 million ($1.17/boe) for 2020 was below our annual guidance of $38 million ($1.30/boe) due to our cost
savings programs. We expect annual G&A expense of $42.0 million ($1.53/boe) for 2021 as we do not expect to benefit from the
CEWS.
Baytex Energy Corp. 2020 Annual Report
17
Financing and Interest Expense
Financing and interest expense includes interest on our credit facilities, long-term notes and lease obligations as well as non-cash
financing costs which include the accretion on our debt issue costs and asset retirement obligations. Financing and interest
expense varies depending on debt levels outstanding during the period, the applicable borrowing rates, CAD/USD foreign
exchange rates, along with the carrying amount of asset retirement obligations and the discount rates used to present value these
obligations.
The following table summarizes our financing and interest expense for the years ended December 31, 2020 and 2019.
($ thousands except for per boe)
Interest on credit facilities
Interest on long-term notes
Interest on lease obligations
Cash interest
Accretion of debt issue costs
Accretion of asset retirement obligations
Early redemption expense
Financing and interest expense
Cash interest per boe
Financing and interest expense per boe
Years Ended December 31
2020
2019
15,256 $
20,376 $
90,830
448
86,431
610
106,534 $
107,417 $
6,617
8,978
3,312 $
4,735
13,713
—
125,441 $
125,865 $
3.65 $
4.30 $
3.01 $
3.53 $
$
$
$
$
$
$
Change
(5,120)
4,399
(162)
(883)
1,882
(4,735)
3,312
(424)
0.64
0.77
Financing and interest expense was $125.4 million ($4.30/boe) in 2020 compared to $125.9 million ($3.53/boe) in 2019.
Cash interest of $106.5 million ($3.65/boe) in 2020 is slightly lower than $107.4 million ($3.01/boe) in 2019. Interest on our credit
facilities was lower in 2020 primarily due to a lower weighted average borrowing rate on amounts outstanding relative to 2019. The
weighted average interest rate on our credit facilities was 2.0% in 2020 compared to 4.0% in 2019. Interest on our long-term notes
was higher in 2020 due to the issuance of the US$500 million principal amount of 8.75% senior unsecured notes. Proceeds from
the issuance of the US$500 million principal amount of 8.75% senior unsecured notes were used to redeem the US$400 million
principal amount of 5.125% senior unsecured notes on February 20, 2020 along with the $300 million principal amount of 6.625%
senior unsecured notes on March 5, 2020.
Financing and interest expense for 2020 also includes the accelerated amortization of debt issue costs and $3.3 million of early
redemption expense associated with the $300 million principal amount of 6.625% senior unsecured notes which were redeemed at
101.104% of the principal amount on March 5, 2020. Accretion of asset retirement obligations of $9.0 million for 2020 was lower
than $13.7 million for 2019 due to a lower risk free discount rate for 2020 relative to 2019.
Cash interest of $106.5 million ($3.65/boe) for 2020 was below our annual guidance of $112.0 million ($3.84/boe). We expect
annual cash interest to be $105.0 million ($3.84/boe) for 2021.
Exploration and Evaluation Expense
Exploration and evaluation ("E&E") expense is related to the expiry of leases and the de-recognition of costs for exploration
programs that have not demonstrated commercial viability and technical feasibility. E&E expense will vary depending on the timing
of expiring leases, the accumulated costs of the expiring leases and the economic facts and circumstances related to the
Company's exploration programs. E&E expense was $14.0 million for 2020 which is higher than $11.8 million for 2019 due to a
higher amount of acreage expiring in 2020 relative to 2019.
18
Baytex Energy Corp. 2020 Annual Report
Depletion and Depreciation
Depletion and depreciation expense varies with the carrying amount of the Company's oil and gas properties, the amount of proved
plus probable reserves volumes and the rate of production for the period. The following table summarizes depletion and
depreciation expense for the years ended December 31, 2020 and 2019.
($ thousands except for per boe)
Depletion
Depreciation
Depletion and depreciation
Depletion and depreciation per boe
Years Ended December 31
2020
2019
Change
$
$
$
478,859 $
725,267 $
(246,408)
7,521
486,380 $
16.66 $
6,419
1,102
731,686 $
(245,306)
20.52 $
(3.86)
Depletion and depreciation expense was $486.4 million ($16.66/boe) for 2020 compared to $731.7 million ($20.52/boe) reported for
2019. Total depletion and depreciation expense was lower in 2020 relative to 2019 due to lower production in 2020 combined with
a reduced depletable base resulting from the $2.6 billion of impairment recorded in Q1/2020.
Impairment
At March 31, 2020, we identified indicators of impairment due to the sharp decline in forecasted commodity prices. We performed
impairment tests on the E&E assets and oil and gas properties for our six CGUs. We recorded total impairments of $2.7 billion in
Q1/2020 as the carrying value of the E&E assets and oil and gas properties exceeded the estimated recoverable amounts of the
CGUs. The total impairment recorded at Q1/2020 includes $2.6 billion related to oil and gas properties and $0.1 billion related to
E&E assets.
At December 31, 2020, with updated development plans, including capital efficiencies and reduced well costs, reflected in our
reserves along with changes in commodity prices, we estimated the recoverable amount for E&E assets and oil and gas properties
in each of our six CGUs. We recorded an impairment reversal of $356.1 million at December 31, 2020 as the estimated
recoverable amount of the Viking and Eagle Ford CGUs exceeded their carrying value. The total impairment reversal recorded at
Q4/2020 includes $341.3 million related to oil and gas properties and $14.8 million related to E&E assets.
At March 31, 2020 the recoverable amount of the Company's CGUs were calculated using the following benchmark reference
prices for the years 2020 to 2029 adjusted for commodity differentials specific to the Company. The prices and costs subsequent to
2029 have been adjusted for inflation at an annual rate of 2.0%.
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
WTI crude oil (US$/bbl)
29.17
40.45
49.17
53.28
55.66
56.87
58.01
59.17
60.35
61.56
WCS heavy oil (CA$/bbl)
19.21
34.65
46.34
51.25
54.28
55.72
56.96
58.22
59.51
60.82
LLS crude oil (US$/bbl)
32.17
43.80
52.55
56.68
59.10
60.35
61.52
62.72
63.94
65.19
Edmonton par oil (CA$/bbl)
29.22
46.85
59.27
65.02
68.43
69.81
71.24
72.70
74.19
75.71
Henry Hub gas (US$/mmbtu)
AECO gas (CA$/mmbtu)
Exchange rate (CAD/USD)
2.10
1.74
1.41
2.58
2.20
1.37
2.79
2.38
1.34
2.86
2.45
1.34
2.93
2.53
1.34
3.00
2.60
1.33
3.07
2.66
1.33
3.13
2.72
1.33
3.19
2.79
1.33
3.25
2.85
1.33
Baytex Energy Corp. 2020 Annual Report
19
The following table summarizes the recoverable amount and impairment at March 31, 2020 and demonstrates the sensitivity of the
estimated recoverable amount of the Company's CGUs comprising oil and gas properties to reasonably possible changes in key
assumptions inherent in the estimate.
Recoverable
amount
Impairment
Change in discount
rate of 1%
Change in oil price
of $2.50/bbl
Change in gas
price of $0.25/mcf
Conventional CGU
$
37,444 $
41,000 $
3,000 $
3,500 $
Peace River CGU
Lloydminster CGU
Duvernay CGU
Viking CGU
Eagle Ford CGU
109,631
227,967
61,197
962,134
1,576,423
345,000
470,000
5,000
915,000
812,488
9,500
25,000
5,500
57,000
120,750
53,500
69,500
9,500
123,000
141,500
$
2,974,796 $
2,588,488 $
220,750 $
400,500 $
8,500
3,000
—
1,500
4,000
32,000
49,000
At December 31, 2020, the recoverable amount of the Company's CGUs were calculated using the following benchmark reference
prices for the years 2021 to 2030 adjusted for commodity differentials specific to the Company. The prices and costs subsequent to
2030 have been adjusted for inflation at an annual rate of 2.0%.
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
WTI crude oil (US$/bbl)
47.17
50.17
53.17
54.97
56.07
57.19
58.34
59.50
60.69
61.91
WCS heavy oil (CA$/bbl)
44.63
48.18
52.10
54.10
55.19
56.29
57.42
58.57
59.74
60.93
LLS crude oil (US$/bbl)
49.50
52.85
55.87
57.69
58.82
59.97
61.15
62.34
63.56
64.83
Edmonton par oil (CA$/bbl)
55.76
59.89
63.48
65.76
67.13
68.53
69.95
71.40
72.88
74.34
Henry Hub gas (US$/mmbtu)
AECO gas (CA$/mmbtu)
Exchange rate (CAD/USD)
2.83
2.78
1.30
2.87
2.70
1.31
2.90
2.61
1.31
2.96
2.65
1.31
3.02
2.70
1.31
3.08
2.76
1.31
3.14
2.81
1.31
3.20
2.87
1.31
3.26
2.92
1.31
3.33
2.98
1.31
The following table summarizes the recoverable amount and impairment reversal at December 31, 2020 and demonstrates the
sensitivity of the estimated recoverable amount of the Company's CGUs comprising oil and gas properties to reasonably possible
changes in key assumptions inherent in the estimate.
Recoverable
amount
Impairment
reversal
Change in discount
rate of 1%
Change in oil price
of $2.50/bbl
Change in gas
price of $0.25/mcf
Conventional CGU
$
54,265 $
— $
1,000 $
3,000 $
Peace River CGU
Lloydminster CGU
Duvernay CGU
Viking CGU
Eagle Ford CGU
104,225
212,979
70,491
1,026,026
1,609,562
—
—
—
116,000
225,326
1,000
7,000
5,500
34,500
91,600
49,500
57,500
12,000
106,500
157,500
$
3,077,548 $
341,326 $
140,600 $
386,000 $
9,000
3,000
500
1,500
5,000
38,400
57,400
Share-Based Compensation Expense
Share-based compensation ("SBC") expense includes expense associated with our Share Award Incentive Plan and our Incentive
Award Plan. SBC expense associated with our Share Award Incentive Plan is recognized in net income or loss over the vesting
period of the awards with a corresponding increase in contributed surplus. SBC expense associated with our Incentive Award Plan
is recognized in net income or loss over the vesting period of the awards with a corresponding financial liability and includes gains
or losses on equity total return swaps used to fix the aggregate cost of new grants made under the plan. SBC expense varies with
the quantity of unvested share awards outstanding and the grant date fair value assigned to the share awards.
We recorded SBC expense of $9.5 million for 2020 which is lower than $15.9 million reported for 2019. SBC expense is lower in
2020 as the total value of awards granted in 2020 was lower than prior years. The total expense for 2020 is comprised of non-cash
compensation expense of $7.2 million related to the Share Award Incentive Plan and cash compensation expense of $2.3 million
related to the Incentive Award Plan.
20
Baytex Energy Corp. 2020 Annual Report
Foreign Exchange
Unrealized foreign exchange gains and losses are primarily a result of changes in the reported amount of our U.S. dollar
denominated long-term notes and our U.S. dollar denominated intercompany notes. The long-term notes and intercompany notes
are translated to Canadian dollars on the balance sheet date using the closing CAD/USD exchange rate resulting in unrealized
gains and losses. Realized foreign exchange gains and losses are due to day-to-day U.S. dollar denominated transactions
occurring in our Canadian functional currency entities.
($ thousands except for exchange rates)
Unrealized foreign exchange loss - intercompany notes (1)
Unrealized foreign exchange gain - long-term notes
Realized foreign exchange (gain) loss
Foreign exchange loss (gain)
CAD/USD exchange rates:
At beginning of period
At end of period
Years Ended December 31
2020
31,617 $
(22,385)
(544)
8,688 $
2019
— $
(62,753)
966
(61,787) $
Change
31,617
40,368
(1,510)
70,475
$
$
1.2965
1.2755
1.3646
1.2965
(1) During 2020, a series of intercompany notes totaling US$751.0 million were issued from a Canadian subsidiary to a U.S. subsidiary. These
notes are eliminated upon consolidation within the Statement of Financial Position and are revalued at the relevant foreign exchange rate at
each period end. Foreign exchange gains or losses incurred within the Canadian subsidiary are recognized in unrealized foreign exchange
gain or loss whereas those within the U.S. subsidiary are recognized in other comprehensive income.
We recorded an unrealized foreign exchange gain on our long-term notes of $22.4 million due to the strengthening of the Canadian
dollar relative to the U.S. dollar at December 31, 2020 compared to December 31, 2019. This compares to an unrealized foreign
exchange gain of $62.8 million in 2019 due to the strengthening of the Canadian dollar relative to the U.S. dollar at December 31,
2019 compared to December 31, 2018.
We recorded an unrealized foreign exchange loss of $31.6 million on our intercompany notes issued by our Canadian subsidiary
due to the strengthening of the Canadian dollar relative to the U.S. dollar at December 31, 2020 from when the intercompany notes
were issued in September 2020 when the CAD/USD rate was 1.3199.
Realized foreign exchange gains and losses will fluctuate depending on the amount and timing of day-to-day U.S. dollar
denominated transactions for our Canadian operations. We recorded a realized foreign exchange gain of $0.5 million for 2020
compared to a loss of $1.0 million for 2019.
Income Taxes
($ thousands)
Current income tax expense
Deferred income tax recovery
Total income tax recovery
Years Ended December 31
2020
574 $
(160,967)
(160,393) $
$
$
2019
2,093 $
(68,555)
(66,462) $
Change
(1,519)
(92,412)
(93,931)
Current income expense was $0.6 million for 2020 compared to $2.1 million recorded in 2019. Current income tax is lower in 2020
due to lower state tax owed on our U.S. operations.
We recorded a deferred income tax recovery of $161.0 million for 2020 compared to $68.6 million for 2019. We recorded a higher
deferred income tax recovery in 2020 primarily due to lower net income before tax as a result of the impairments recorded in 2020.
The recovery for 2020 was reduced by a change in valuation allowance of $444.1 million which was recognized against certain
deferred tax assets due to uncertainty of future cash flows.
As disclosed in the 2019 annual financial statements, certain indirect subsidiaries received reassessments from the Canada
Revenue Agency (the "CRA”) that deny $591.0 million of non-capital loss deductions relevant to the calculation of income taxes for
the years 2011 through 2015. In September 2016, we filed notices of objection with the CRA appealing each reassessment
received. There has been no change in the status of these reassessments since an Appeals Officer was assigned to our file in July
2018. We remain confident that our original tax filings are correct and intend to defend these tax filings through the appeals
process.
Baytex Energy Corp. 2020 Annual Report
21
Canadian Tax Pools ($ thousands)
Canadian oil and natural gas property expenditures
Canadian development expenditures
Canadian exploration expenditures
Undepreciated capital costs
Non-capital losses
Financing costs and other
Total Canadian tax pools
U.S. Tax Pools ($ thousands)
Depletion
Intangible drilling costs
Tangibles
Non-capital losses
Other
Total U.S. tax pools
Net Income (Loss) and Adjusted Funds Flow
December 31, 2020
449,670 $
557,554
10,907
347,297
1,015,152
14,780
2,395,360 $
147,160 $
5,521
39,028
1,150,068
192,495
1,534,272 $
$
$
$
$
December 31, 2019
492,616
696,298
9,726
433,768
705,298
4,424
2,342,130
156,184
18,618
64,496
1,009,260
452,710
1,701,268
The components of adjusted funds flow and net income or loss for the years ended December 31, 2020 and 2019 are set forth in
the following table.
($ thousands)
Petroleum and natural gas sales
Royalties
Revenue, net of royalties
Expenses
Operating
Transportation
Blending and other
Operating netback
General and administrative
Cash financing and interest
Realized financial derivatives gain
Realized foreign exchange gain (loss)
Other income
Current income tax recovery
Share-based compensation
Adjusted funds flow
Exploration and evaluation
Depletion and depreciation
Non-cash share-based compensation
Non-cash financing and accretion
Non-cash other income
Unrealized financial derivatives loss
Unrealized foreign exchange (loss) gain
Gain on dispositions
Impairment
Deferred income tax recovery
Net loss
22
Baytex Energy Corp. 2020 Annual Report
Years Ended December 31
2020
2019
$
975,477 $
1,805,919 $
(163,735)
811,742
(320,241)
1,485,678
(331,345)
(28,437)
(48,381)
(397,716)
(43,942)
(68,795)
Change
(830,442)
156,506
(673,936)
66,371
15,505
20,414
$
403,579 $
975,225 $
(571,646)
(34,268)
(106,534)
47,836
544
3,176
(574)
(2,253)
(45,469)
(107,417)
75,620
(966)
7,526
(2,093)
—
11,201
883
(27,784)
1,510
(4,350)
1,519
(2,253)
$
311,506 $
902,426 $
(590,920)
(14,011)
(486,380)
(7,216)
(18,907)
2,128
(18,500)
(9,232)
901
(11,764)
(731,686)
(15,894)
(18,448)
—
(82,817)
62,753
2,238
(2,247)
245,306
8,678
(459)
2,128
64,317
(71,985)
(1,337)
(2,360,220)
160,967
(187,822)
(2,172,398)
68,555
92,412
$
(2,438,964) $
(12,459) $
(2,426,505)
We generated adjusted funds flow of $311.5 million for 2020 compared to $902.4 million for 2019. The decrease in adjusted funds
flow for 2020 is primarily due to the decline in commodity benchmark prices and lower production, which resulted in a $653.5
million decrease in revenue, net of royalties and blending and other expense. This decrease in adjusted funds flow in 2020 relative
to 2019 was mitigated by our costs saving initiatives which resulted in a $93.1 million reduction in operating, transportation, and
general and administrative expenses.
We reported a net loss of $2.4 billion for 2020 compared to $12.5 million for 2019. The net loss for 2020 was primarily a result of
impairments of $2.4 billion along with lower commodity prices and production which resulted in a $590.9 million decrease in
adjusted funds flow. This was partially offset by lower depletion and depreciation in 2020 compared to 2019.
Other Comprehensive Income (Loss)
Other comprehensive income or loss is comprised of the foreign currency translation adjustment on U.S. net assets which includes
a series of intercompany debt instruments outstanding between our Canadian and U.S. subsidiaries. Foreign exchange gains or
losses on the debt owing from the U.S. subsidiary is recorded in other comprehensive income and the offsetting foreign exchange
gain or loss on debt owed to the Canadian subsidiary is included in profit and loss for the period.
The $62.8 million foreign currency translation gain for 2020 is a result of the U.S. dollar strengthening during Q1/2020 as we had a
higher amount of U.S. net assets prior to impairment recorded at March 31, 2020. U.S. net assets were lower as a result of the
impairment as the Canadian dollar strengthened relative to the U.S. dollar over the remainder of 2020. The foreign currency
translation adjustment for 2020 also includes a gain of $31.6 million related to the remeasurement of intercompany notes in our
U.S. subsidiary. The CAD/USD exchange rate was 1.2755 at December 31, 2020 compared to 1.4120 at March 31, 2020 and
1.2965 at December 31, 2019.
Capital Expenditures
Capital expenditures for the years ended December 31, 2020 and 2019 are summarized as follows.
Years Ended December 31
2020
2019
($ thousands)
Canada
U.S.
Total
Canada
U.S.
Total
Drilling, completion and equipping
$
143,013 $
104,599 $
247,612 $
319,417 $
166,094 $
485,511
Facilities
Land, seismic and other
Total exploration and development
Acquisitions, net of proceeds from
divestitures
$
$
26,043
5,896
21
768
26,064
6,664
41,141
13,805
10,220
1,614
51,361
15,419
174,952 $
105,388 $
280,340 $
374,363 $
177,928 $
552,291
(182) $
— $
(182) $
2,180 $
— $
2,180
Exploration and development expenditures were $280.3 million for 2020 compared to $552.3 million for 2019. Expenditures were
lower in 2020 compared to 2019 as we adjusted our development programs in the U.S. and Canada in response to the volatility in
crude oil prices throughout 2020. We were active on our properties early in 2020 as crude oil prices were stable and supported
active development. After the significant decline in crude oil prices in March 2020, we moderated the pace of development in the
U.S. and suspended our operated capital activity in Canada. We re-started development activity on our light oil properties as crude
oil prices increased during Q4/2020 and the outlook for global demand improved.
In Canada, we invested $175.0 million on exploration and development activities in 2020 which is $199.4 million lower than
$374.4 million in 2019. Exploration and development activity in 2020 includes costs associated with drilling 104 (101.2 net) light oil
wells, 33 (33.0 net) heavy oil wells, 2 (2.0 net) conventional natural gas wells, 6 (6.0 net) stratigraphic exploration wells and
investing $26.0 million on facilities. Exploration and development expenditures of $374.4 million for 2019 included costs associated
with drilling 279 (247.8 net) light oil wells, 42 (42.0 net) heavy oil wells, 4 (4.0 net) stratigraphic exploration wells, along with
$41.1 million of associated facility expenditures. Total exploration and development costs were lower in 2020 relative to 2019 as we
suspended development operations following the sharp decline in crude oil pricing in March 2020.
Total U.S. exploration and development expenditures were $105.4 million for 2020 which is $72.5 million lower than $177.9 million
for 2019. Exploration and development expenditures of $105.4 million for 2020 included costs associated with the drilling of 65
(16.3 net) wells along with completing 62 (14.1 net) wells that were brought on production. Development expenditures were lower
in 2020 due to lower drilling and completions activity relative to 2019 when we spent $177.9 million and drilled 96 (20.2 net) wells
and brought 109 (25.1 net) wells on production.
We completed minor acquisition and disposition transactions in 2020 for net proceeds of $0.2 million compared to net consideration
of $2.2 million in 2019.
Baytex Energy Corp. 2020 Annual Report
23
Total exploration and development expenditures of $280.3 million for 2020 approximated the mid-point of our annual guidance
range of $260 - $290 million. We expect annual exploration and development expenditures of $225 - $275 million for 2021.
CAPITAL RESOURCES AND LIQUIDITY
We took action to improve our capital structure and financial liquidity during 2020. On February 5, 2020, we issued US$500 million
of senior unsecured notes bearing interest at 8.75% which mature on April 1, 2027. Proceeds from the issuance were used in
conjunction with availability on our credit facilities to complete the early redemption of the US$400 million principal amount of
5.125% senior unsecured notes due June 1, 2021 and the $300 million principal amount of 6.625% senior unsecured notes due
July 19, 2022. We also negotiated an extension to the maturity of our credit facilities from April 2, 2021 to April 2, 2024. As a result
of these actions we do not have any debt maturities until 2024 and we had $367.2 million of undrawn capacity on our credit
facilities at December 31, 2020.
Our objective for capital management involves maintaining a flexible capital structure and sufficient sources of liquidity to execute
our capital programs, while meeting our short and long-term commitments. We strive to actively manage our capital structure in
response to changes in economic conditions. At December 31, 2020, our capital structure was comprised of shareholders' capital,
long-term notes, trade and other receivables, trade and other payables and the credit facilities.
During 2020 we took additional action to protect our financial liquidity in response to lower oil prices and the global economic
instability related to the COVID-19 pandemic. Our 2020 exploration and development expenditures were reduced by moderating
the pace of activity in the U.S. and suspending drilling and completion operations in Canada. Certain high cost, low margin,
production was shut-in for a portion of 2020 when netbacks were challenged by low commodity prices. Our cost savings initiatives
also resulted in lower operating expenses and general and administrative costs during 2020. We have also taken advantage of all
government assistance programs available to our industry. As a result of these actions, we were able to maintain our liquidity and
generate free cash flow of $18.1 million for 2020 during a period of extremely volatile commodity prices.
The capital-intensive nature of our operations requires us to maintain adequate sources of liquidity to fund ongoing capital
programs. Our capital resources consist primarily of adjusted funds flow, available credit facilities and proceeds received from the
divestiture of oil and gas properties. We believe that our internally generated adjusted funds flow and our existing undrawn credit
facilities will provide sufficient liquidity to fund our planned capital expenditures. Adjusted funds flow depends on a number of
factors, including commodity prices, production and sales volumes, royalties, operating expenses, taxes and foreign exchange
rates. In order to manage our capital structure and liquidity, we may from time-to-time issue or repurchase equity or debt securities,
enter into business transactions including the sale of assets or adjust capital spending to manage current and projected debt levels.
There is no certainty that any of these additional sources of capital would be available if required.
At December 31, 2020, net debt of $1.85 billion was $24.2 million lower than $1.87 billion at December 31, 2019. Free cash flow of
$18.1 million generated in 2020 was directed towards debt repayment and reduced net debt at December 31, 2020. The decrease
in net debt was also the result of a $22.4 million decrease in the reported amount of our U.S. dollar denominated net debt due to
the strengthening of the Canadian dollar at December 31, 2020 relative to December 31, 2019. These decreases were partially
offset by transaction and financing costs of $17.6 million related to the refinancing transactions in Q1/2020.
We monitor our capital structure and liquidity requirements using a net debt to adjusted funds flow ratio calculated on a twelve-
month trailing basis. At December 31, 2020, our net debt to adjusted funds flow ratio was 5.9 compared to a ratio of 2.1 as at
December 31, 2019. The increase in the net debt to adjusted funds flow ratio relative to December 31, 2019 is attributed to lower
adjusted funds flow due to lower commodity pricing during 2020.
Credit Facilities
At December 31, 2020, the principal amount of credit facilities and letters of credit outstanding was $666.2 million and we had
approximately $367.2 million of undrawn capacity under our credit facilities that total approximately $1,033.4 million. Our credit
facilities include US$575 million of revolving credit facilities and a $300 million non-revolving term loan (collectively, the "Credit
Facilities").
On March 3, 2020, we amended our Credit Facilities to extend maturity from April 2, 2021 to April 2, 2024. These facilities will
automatically be extended to June 4, 2024 providing we have either refinanced, or have the ability to repay, the outstanding 2024
long-term notes with existing credit capacity as of April 1, 2024.
The Credit Facilities are not borrowing base facilities and do not require annual or semi-annual reviews. The Credit Facilities
contain standard commercial covenants in addition to the financial covenants detailed below. There are no mandatory principal
payments required prior to maturity which could be extended upon our request. Advances (including letters of credit) under the
Credit Facilities can be drawn in either Canadian or U.S. funds and bear interest at the bank’s prime lending rate, bankers’
acceptance discount rates or London Interbank Offered Rates ("LIBOR"), plus applicable margins.
24
Baytex Energy Corp. 2020 Annual Report
The LIBOR benchmark will no longer be published after December 31, 2021. We expect the LIBOR benchmark to be replaced with
an alternative that will apply to our U.S. dollar borrowing at our option. We do not expect this change to have a material impact to
Baytex as U.S. dollar borrowings under the credit facilities can also bear interest at the U.S. base loan rate.
The agreements and associated amending agreements relating to the Credit Facilities are accessible on the SEDAR website at
www.sedar.com.
The weighted average interest rate on the Credit Facilities was 2.0% for 2020 as compared to 4.0% for 2019.
Financial Covenants
At December 31, 2020, we were in compliance with all of the covenants contained in our Credit Facilities and we expect to remain
in compliance with the financial covenants applicable to our credit facilities at current forward commodity prices. A decrease or a
sustained period of low commodity prices may result in non-compliance with our financial covenants and reduced liquidity on our
existing credit facilities. Non-compliance with the financial covenants in our credit facilities could result in our debt becoming due
and payable on demand.
The following table summarizes the financial covenants applicable to the Credit Facilities and our compliance therewith at
December 31, 2020.
Covenant Description
Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio)
Interest Coverage (3) (Minimum Ratio)
Position as at
December 31, 2020
1.6:1.0
3.9:1.0
Covenant
3.5:1.0
2.0:1.0
(1)
(2)
(3)
"Senior Secured Debt" is defined as the principal amount of the credit facilities and other secured obligations identified in the credit agreement.
As at December 31, 2020, the Company's Senior Secured Debt totaled $666.2 million which includes $651.2 million of principal amounts
outstanding and $15.0 million of letters of credit.
"Bank EBITDA" is calculated based on terms and definitions set out in the credit agreement which adjusts net income or loss for financing and
interest expenses, income tax, non-recurring losses, certain specific unrealized and non-cash transactions (including depletion, depreciation,
exploration and evaluation expenses, impairment, deferred income tax expense and recovery, unrealized gains and losses on financial
derivatives and foreign exchange and share-based compensation) and is calculated based on a trailing twelve-month basis including the
impact of material acquisitions as if they had occurred at the beginning of the twelve month period. Bank EBITDA for the twelve months ended
December 31, 2020 was $414.9 million.
"Interest coverage" is computed as the ratio of Bank EBITDA to financing and interest expenses, excluding accretion of debt issue costs and
asset retirement obligations, and is calculated on a trailing twelve-month basis. Financing and interest expenses, excluding accretion of debt
issue costs and asset retirement obligations, for the twelve months ended December 31, 2020 were $106.1 million.
Long-Term Notes
We have two series of long-term notes outstanding that total $1.15 billion as at December 31, 2020. The long-term notes do not
contain any financial maintenance covenants but contain a debt incurrence covenant that restricts our ability to raise additional debt
beyond our existing Credit Facilities and long-term notes.
On June 6, 2014, we issued US$800 million of senior unsecured notes, comprised of US$400 million of 5.125% notes due
June 1, 2021 (the "5.125% Notes"), which were redeemed February 20, 2020, and US$400 million of 5.625% notes due June 1,
2024 (the "5.625% Notes"), which remain outstanding. The 5.625% Notes pay interest semi-annually with the principal amount
repayable at maturity. As of June 1, 2019, the 5.625% Notes are redeemable at our option, in whole or in part, at specified
redemption prices and will be redeemable at par from June 1, 2022 to maturity.
On February 5, 2020, we issued US$500 million aggregate principal amount of senior unsecured notes due April 1, 2027 bearing
interest at a rate of 8.75% per annum payable semi-annually (the "8.75% Senior Notes)". The 8.75% Senior Notes are redeemable
at our option, in whole or in part, at specified redemption prices after April 1, 2023 and will be redeemable at par from April 1, 2026
to maturity. Transaction costs of $12.5 million were incurred in conjunction with the issuance which resulted in net proceeds of
$652.2 million.
On February 20, 2020, we used a portion of the net proceeds from the issuance of the 8.75% Senior Notes to complete the early
redemption of the US$400 million principal amount of the 5.125% senior unsecured notes due June 1, 2021 at par plus accrued
interest. The payment at redemption was $530.4 million.
On March 5, 2020, we completed the early redemption of the $300 million principal amount of the 6.625% senior unsecured notes
due July 19, 2022 at 101.104% of the principal amount plus accrued interest. The payment at redemption includes principal of
$300.0 million plus early redemption expense of $3.3 million.
Baytex Energy Corp. 2020 Annual Report
25
Shareholders’ Capital
We are authorized to issue an unlimited number of common shares and 10.0 million preferred shares. The rights and terms of
preferred shares are determined upon issuance. During the year ended December 31, 2020, we issued 2.9 million common shares
pursuant to our share-based compensation program. As at February 24, 2021, we had 561.2 million common shares issued and
outstanding and no preferred shares issued and outstanding.
Contractual Obligations
We have a number of financial obligations that are incurred in the ordinary course of business. These obligations are of a recurring
nature and impact our adjusted funds flow in an ongoing manner. A significant portion of these obligations will be funded by
adjusted funds flow. These obligations as of December 31, 2020 and the expected timing for funding these obligations are noted in
the table below.
($ thousands)
Trade and other payables
Credit facilities (1) (2)
Long-term notes (2)
Interest on long-term notes (3)
Lease agreements (2)
Processing agreements
Transportation agreements
Total
Total
Less than
1 year
$
155,955 $
155,955 $
651,173
1,147,950
446,854
11,850
6,361
98,406
—
—
84,502
4,504
836
16,698
1-3 years
3-5 years Beyond 5 years
— $
—
—
169,004
4,302
1,320
40,351
— $
651,173
510,200
123,479
3,044
474
24,903
—
—
637,750
69,869
—
3,731
16,454
$
2,518,549 $
262,495 $
214,977 $
1,313,273 $
727,804
(1) The credit facilities mature on April 2, 2024. Maturity will automatically be extended to June 4, 2024 providing Baytex has either refinanced, or
has the ability to repay, the outstanding 2024 long-term notes with existing credit capacity as of April 1, 2024.
(2) Principal amount of instruments.
(3) Excludes interest on our credit facilities as interest payments fluctuate based on a floating rate of interest and changes in the outstanding
balances.
We also have ongoing obligations related to the abandonment and reclamation of well sites and facilities when they reach the end
of their economic lives. Programs to abandon and reclaim well sites and facilities are undertaken regularly in accordance with
applicable legislative requirements.
26
Baytex Energy Corp. 2020 Annual Report
FOURTH QUARTER OPERATING AND FINANCIAL RESULTS
($ thousands except for per boe)
Canada
U.S.
Total
Canada
U.S.
Total
Three Months Ended December 31
2020
2019
Total daily production
Light oil and condensate (bbl/d)
Heavy oil (bbl/d)
NGL (bbl/d)
Total liquids (bbl/d)
Natural gas (mcf/d)
Total production (boe/d)
Operating netback ($/boe)
Light oil and condensate ($/bbl)
Heavy oil ($/bbl)
NGL ($/bbl)
Natural gas ($/mcf)
Total sales, net of blending and other per boe
Royalties per boe
Operating expense per boe
Transportation expense per boe
15,212
21,725
1,364
38,301
42,117
45,321
14,356
—
5,131
19,487
33,999
25,154
29,568
21,725
6,495
57,788
76,116
70,475
21,531
27,050
1,170
49,751
48,260
57,794
22,375
—
7,529
43,906
27,050
8,699
29,904
79,655
51,975
100,235
38,566
96,360
$
47.43 $
52.73 $
50.00 $
65.31 $
76.46 $
27.87
16.57
2.50
32.10
—
19.18
3.26
38.41
27.87
18.63
2.84
34.35
40.32
16.22
2.39
45.52
—
18.75
3.20
52.33
71.00
40.32
18.41
2.81
48.25
(2.90)
(11.11)
(5.83)
(4.73)
(14.69)
(8.72)
(14.73)
(1.60)
(7.92)
(12.30)
—
(1.03)
(14.41)
(1.66)
(6.47)
(11.23)
—
(1.00)
Operating netback per boe
$
12.87 $
19.38 $
15.19 $
24.72 $
31.17 $
27.30
Financial
Petroleum and natural gas sales
$ 144,741 $ 88,895 $ 233,636 $ 260,217 $ 185,678 $ 445,895
Royalties
(12,092)
(25,715)
(37,807)
(25,154)
(52,128)
(77,282)
Revenue, net of royalties
132,649
63,180
195,829
235,063
133,550
368,613
Operating
Transportation
Blending and other
Operating netback
General and administrative
Cash interest
Realized financial derivatives gain
Other
Adjusted funds flow
Net income (loss)
(61,409)
(18,339)
(79,748)
(76,623)
(22,950)
(99,573)
(6,692)
(10,891)
—
—
(6,692)
(8,840)
(10,891)
(18,167)
—
—
(8,840)
(18,167)
$ 53,657 $ 44,841 $ 98,498 $ 131,433 $ 110,600 $ 242,033
—
—
—
—
—
—
—
306
(9,314)
(25,194)
17,105
1,081
—
—
—
—
—
—
—
—
(9,893)
(24,389)
22,956
1,440
$ 53,657 $ 45,147 $ 82,176 $ 131,433 $ 110,600 $ 232,147
$ 112,954 $ 144,200 $ 221,160 $ (134,348) $ 44,937 $ (117,772)
Exploration and development expenditures
$ 45,030 $ 32,779 $ 77,809 $ 104,460 $ 48,657 $ 153,117
Acquisitions, net of proceeds from divestitures
$
(33) $
— $
(33) $
563 $
— $
563
Net debt
$ 1,847,601
$ 1,871,791
Baytex Energy Corp. 2020 Annual Report
27
Benchmark Averages
WTI oil (US$/bbl) (1)
MEH oil (US$/bbl) (2)
MEH oil differential to WTI (US$/bbl)
Edmonton par oil ($/bbl)
Edmonton par oil differential to WTI (US$/bbl)
WCS heavy oil ($/bbl) (3)
WCS heavy oil differential to WTI (US$/bbl)
AECO natural gas price ($/mcf) (4)
NYMEX natural gas price (US$/mmbtu) (5)
CAD/USD average exchange rate
Three Months Ended December 31
2020
2019
Change
42.66
43.05
0.39
50.24
(4.11)
43.46
(9.31)
2.77
2.66
1.3031
56.96
60.04
3.08
68.10
(5.37)
54.29
(15.83)
2.34
2.50
1.3201
(14.30)
(16.99)
(2.69)
(17.86)
1.26
(10.83)
6.52
0.43
0.16
(0.0170)
(1) WTI refers to the arithmetic average of NYMEX prompt month WTI for the applicable period.
(2) MEH refers to arithmetic average of the Argus WTI Houston differential weighted index price for the applicable period.
(3) WCS refers to the average posting price for the benchmark WCS heavy oil.
(4) AECO refers to the AECO arithmetic average month-ahead index price published by the Canadian Gas Price Reporter ("CGPR").
(5) NYMEX refers to the NYMEX last day average index price as published by the CGPR.
Our operating and financial results for Q4/2020 reflect additional development activity after we limited exploration and development
expenditures for two quarters in response to the challenging market conditions caused by COVID-19. We invested $77.8 million on
exploration and development expenditures in Q4/2020 which were focused on our light oil assets in the U.S. and in Canada.
Adjusted funds flow was $82.2 million for Q4/2020 and production of 70,475 boe/d was in line with expectations after two quarters
of limited development spending.
In Canada, production averaged 45,321 boe/d in Q4/2020 which was 12,473 boe/d lower than 57,794 boe/d reported for Q4/2019.
The decrease in production reflects lower exploration and development activity throughout 2020 relative to 2019. Our weighted
average realized price of $32.10/boe for Q4/2020 was $13.42/boe lower than $45.52/boe for Q4/2019 due to a decrease in
benchmark prices in Q4/2020 relative to Q4/2019. In Q4/2020, the Edmonton Par benchmark was $50.24/bbl and the WCS heavy
oil price was $43.46/bbl compared to $68.10/bbl and $54.29/bbl for the same period of 2019, respectively. As a result of lower
production and benchmark pricing, we generated operating netback of $53.7 million ($12.87/boe) for Q4/2020 which was
$77.8 million ($11.85/boe) lower than $131.4 million ($24.72/boe) reported for Q4/2019. Exploration and development expenditures
of $45.0 million in Q4/2020 includes drilling and completion costs associated with 32 (32.0 net) wells compared to 73 (70.7 net)
wells in Q4/2019 when we spent $104.5 million.
In the U.S., production averaged 25,154 boe/d for Q4/2020 which is 13,412 boe/d lower than 38,566 boe/d reported for Q4/2019.
The decrease in production reflects lower exploration and development activity throughout 2020 relative to 2019. Our realized price
of $38.41/boe was $13.92/boe lower than our realized price of $52.33/boe in Q4/2019 due to a decrease in benchmark prices in
Q4/2020 relative to Q4/2019. The MEH benchmark averaged US$43.05/bbl in Q4/2020 which is US$16.99/boe lower than
US$60.04/bbl during Q4/2019. Operating netback of $44.8 million ($19.38/boe) was $65.8 million ($11.79/boe) lower than
$110.6 million ($31.17/boe) for Q4/2019 due to lower benchmark prices and lower production in Q4/2020. Exploration and
development expenditures of $32.8 million in Q4/2020 includes costs associated with drilling 26 (7.1 net) wells and commencing
production from 9 (2.7 net) wells. Exploration and development expenditures were lower in Q4/2020 due to lower completion
activity and a reduction in well costs relative to Q4/2019 when we spent $48.7 million and drilled 27 (6.3 net) wells and brought 24
(6.5 net) wells on production.
We generated adjusted funds flow of $82.2 million in Q4/2020 which is $150.0 million lower than $232.1 million in Q4/2019. The
decrease in adjusted funds flow in Q4/2020 is due to lower realized pricing driven by the decline in benchmark pricing along with
lower production due to lower capital spending in 2020. Production of 70,475 boe/d in Q4/2020 compared to 96,360 boe/d for
Q4/2019 was a result of limited exploration and development activity during Q2/2020 and Q3/2020 relative to the same periods of
2019. Operating netback of $15.19/boe in Q4/2020 is $12.11/boe lower relative to $27.30/boe in Q4/2019 and reflects the impact
that lower benchmark prices had on our realized pricing. The decrease in our realized price combined with the impact of lower
production resulted in an $143.5 million decrease in operating netback in Q4/2020 compared to Q4/2019. We recorded a realized
financial derivatives gain of $17.1 million in Q4/2020 compared to $23.0 million in Q4/2019. G&A expense of $9.3 million in
Q4/2020 was lower than $9.9 million in Q4/2019 due to lower staffing and our cost saving initiatives, which included salary
reductions. Interest expense of $25.2 million in Q4/2020 was $0.8 million higher than $24.4 million for Q4/2019 due to an increase
in interest on long-term notes, partially offset by a reduction in interest on our credit facilities due to lower interest rates in Q4/2020
relative to Q4/2019. Net debt decreased from $1.87 billion in Q4/2019 to $1.85 billion in Q4/2020 due to the strengthening of the
Canadian dollar relative to the U.S. dollar combined with debt repayment with free cash flow generated during 2020.
28
Baytex Energy Corp. 2020 Annual Report
We recorded net income of $221.2 million in Q4/2020 compared to a net loss of $117.8 million in Q4/2019. Net income for Q4/2020
includes $341.3 million associated with the reversal of impairments due to a decrease in well costs in our Eagle Ford and Viking
business units. In Q4/2019 we recorded an impairment expense of $187.8 million due to the sustained decline in Canadian heavy
oil prices which resulted in a change in development plans for our thermal projects in Peace River.
QUARTERLY FINANCIAL INFORMATION
($ thousands, except per common share
amounts)
Petroleum and natural gas sales
Net income (loss)
Per common share - basic
Per common share - diluted
Adjusted funds flow
Per common share - basic
Per common share - diluted
Exploration and development
Canada
U.S.
2020
2019
Q4
233,636
221,160
0.39
0.39
Q3
Q2
Q1
Q4
Q3
Q2
Q1
252,538
152,689
336,614
445,895
424,600
482,000
453,424
(23,444) (138,463) (2,498,217)
(117,772)
15,151
78,826
11,336
(0.04)
(0.04)
(0.25)
(0.25)
(4.46)
(4.46)
(0.21)
(0.21)
0.03
0.03
0.14
0.14
0.02
0.02
82,176
78,508
17,887
132,935
232,147
213,379
236,130
220,770
0.15
0.15
77,809
45,030
32,779
0.14
0.14
15,902
3,882
12,020
0.03
0.03
9,852
2,929
6,923
0.24
0.24
0.42
0.42
0.38
0.38
0.42
0.42
0.40
0.40
176,777
153,117
139,085
106,246
153,843
123,110
104,460
53,667
48,657
96,774
42,311
68,259
104,870
37,987
48,973
Acquisitions, net of divestitures
(33)
(98)
(11)
(40)
563
(30)
1,647
—
Net debt
Total assets
1,847,601 1,906,079 1,994,953 2,051,617 1,871,791 1,971,339 2,028,686 2,175,241
3,408,096 3,156,414 3,267,820 3,441,040 5,914,083 6,233,875 6,222,190 6,359,157
Common shares outstanding
561,227
561,163
560,545
560,483
558,305
557,972
556,798
555,872
Daily production
Total production (boe/d)
Canada (boe/d)
U.S. (boe/d)
Benchmark prices
WTI oil (US$/bbl)
WCS heavy ($/bbl)
Edmonton Light ($/bbl)
CAD/USD avg exchange rate
AECO gas ($/mcf)
NYMEX gas (US$/mmbtu)
Sales price ($/boe)
Royalties ($/boe)
Operating expense ($/boe)
Transportation expense ($/boe)
Operating netback ($/boe)
Financial derivatives gain (loss) ($/boe)
Operating netback after financial
derivatives ($/boe)
70,475
45,321
25,154
77,814
49,164
28,650
72,508
37,691
34,817
98,452
62,262
36,190
96,360
57,794
38,566
94,927
58,134
36,793
98,402
101,115
58,580
39,822
60,018
41,097
42.66
43.46
50.24
1.3031
2.77
2.66
34.35
(5.83)
(12.30)
(1.03)
15.19
2.64
40.93
42.40
49.83
27.85
22.70
29.85
46.17
34.48
51.43
56.96
54.29
58.10
56.45
58.39
68.41
59.81
65.73
73.84
54.90
56.64
66.53
1.3316
1.3860
1.3445
1.3201
1.3207
1.3376
1.3293
2.18
1.98
1.91
1.72
2.14
1.95
2.34
2.50
1.04
2.23
1.17
2.64
1.94
3.15
33.79
(5.59)
22.31
(4.42)
35.19
(6.33)
48.25
(8.72)
47.14
(8.59)
51.49
(9.67)
47.98
(8.94)
(10.26)
(11.17)
(11.66)
(11.23)
(11.15)
(11.22)
(11.02)
(0.89)
17.05
(1.36)
(0.76)
5.96
2.06
(1.15)
16.05
3.00
(1.00)
27.30
2.59
(1.13)
26.27
2.39
(1.33)
29.27
1.45
(1.46)
26.56
2.07
17.83
15.69
8.02
19.05
29.89
28.66
30.72
28.63
Our results for the previous eight quarters reflect the disciplined execution of our development programs and management of
production in response to fluctuations in the prices for the commodities we produce. Production was 101,115 boe/d during Q1/2019
as stable crude oil prices supported an active development program in Canada and the U.S. Production was relatively consistent in
the quarters following Q1/2019 until we shut-in production in Canada and moderated the pace of activity in the U.S. after the sharp
decline in crude oil prices in March 2020. Production of 70,475 boe/d for Q4/2020 reflects reduced capital spending in Q2/2020 and
Q3/2020 in response to low commodity prices.
North American benchmark commodity prices were stable throughout 2019 and were relatively strong leading into Q1/2020 with the
WTI benchmark price averaging US$57.53/bbl in January. Decisions made by Saudi Arabia and Russia to increase production of
crude oil as demand was decreasing due to the spread of COVID-19 resulted in a sharp decline in global crude oil prices with WTI
averaging US$27.85/bbl in Q2/2020. Prices improved during the second half of 2020 as OPEC+ agreed to reinstate production
Baytex Energy Corp. 2020 Annual Report
29
curtailments and measures to control the spread of COVID-19 were relaxed. Despite this recent improvement, commodity prices
remained lower than Q1/2020 levels with WTI averaging US$42.66/bbl for Q4/2020. The impact of low commodity prices is
reflected in our realized sales price of $34.35/boe for Q4/2020. Our development programs were significantly reduced in Canada
and the U.S. for 2020 as a result of the decline in crude oil pricing with limited exploration and development spending during
Q2/2020 and Q3/2020. Exploration and development spending of $77.8 million during Q4/2020 reflects the improving outlook for
crude oil prices leading into 2021.
Adjusted funds flow is directly impacted by our average daily production and changes in benchmark commodity prices which are
the basis for our realized sales price. Adjusted funds flow improved throughout 2019 due to increased production and strong well
performance along with higher realizations associated with the higher weighting of light oil production. Adjusted funds flow of
$82.2 million in Q4/2020 reflects the impact of lower commodity prices and reduced development expenditures which resulted in
lower production relative to 2019.
Net debt can fluctuate on a quarterly basis depending on the timing of exploration and development expenditures, changes in our
adjusted funds flow and the closing CAD/USD exchange rate which is used to translate our U.S. dollar denominated debt. Net debt
has decreased from $2.2 billion at Q1/2019 to $1.8 billion at Q4/2020, which is primarily due to adjusted funds flow exceeding
exploration and development expenditures by $381.3 million over the last eight quarters, which reflects our efforts to preserve
liquidity during periods of challenging commodity prices. Our net debt has also been reduced by a decrease in the CAD/USD
exchange rate used to translate our U.S. dollar denominated debt from 1.3360 CAD/USD at Q1/2019 to 1.2755 CAD/USD at
Q4/2020.
OFF BALANCE SHEET TRANSACTIONS
We do not have any financial arrangements that are excluded from the consolidated financial statements as at December 31, 2020,
nor are any such arrangements outstanding as of the date of this MD&A.
CRITICAL ACCOUNTING ESTIMATES
The preparation of the consolidated financial statements in accordance with IFRS requires management to make judgments,
estimates and assumptions that affect the application of accounting policies and reported amounts of assets, liabilities, revenues
and expenses. These judgments, estimates and assumptions are based on all relevant information available to the Company at the
time of financial statement preparation. Actual results can differ from those estimates as the effect of future events cannot be
determined with certainty. The key areas of judgment or estimation uncertainty that have a significant risk of causing material
adjustment to the reported amounts of assets, liabilities, revenues, and expenses are discussed below.
Reserves
The Company uses estimates of oil, natural gas and NGL reserves in the calculation of depletion and in the determination of fair
value estimates for non-financial assets. The process to estimate reserves is complex and requires significant judgment. Estimates
of the Company's reserves are evaluated annually by independent reserves evaluators and represent the estimated recoverable
quantities of oil, natural gas and NGL and the related net cash flows. This evaluation of reserves is prepared in accordance with the
reserves definition contained in National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities" and the Canadian
Oil and Gas Evaluation Handbook.
Estimates of economically recoverable oil, natural gas and NGL and their future net cash flows are based on a number of factors
and assumptions. Changes to estimates and assumptions such as forward price forecasts, production rates, ultimate reserve
recovery, timing and amount of capital expenditures, production costs, marketability of oil and natural gas, royalty rates and other
geological, economic and technical factors could have a significant impact on reported reserves. Changes in the Company's
reserves estimates can have a significant impact on the carrying values of the Company's oil and gas properties, the calculation of
depletion, the timing of cash flows for asset retirement obligations, asset impairments and estimates of fair value determined in
accounting for business combinations.
Cash-generating Units ("CGUs")
The Company's oil and gas properties are aggregated into CGUs which are the smallest identifiable group of assets that generates
cash flows that are largely independent of the cash flows from other assets or groups of assets. The aggregation of assets in CGUs
requires management judgment and is based on geographical proximity, shared infrastructure and similar exposure to market risk.
30
Baytex Energy Corp. 2020 Annual Report
Identification of Impairment and Impairment Reversal Indicators
Judgment is required to assess when indicators of impairment or impairment reversal exist and when a calculation of the
recoverable amount is required. The CGUs comprising oil and gas properties are reviewed at each reporting date to assess
whether there is any indication of impairment or impairment reversal. The assessment for each CGU considers significant changes
in reservoir performance including forecasted production volumes, forecasted royalty, operating, capital and abandonment and
reclamation costs, forecasted oil and gas prices and the resulting cash flows from proved plus probable oil and gas reserves.
Measurement of Recoverable Amount
If indicators of impairment or impairment reversal are determined to exist, the recoverable amount of an asset or CGU is calculated
based on the higher of value-in-use ("VIU") and fair value less cost of disposal ("FVLCD"). These calculations require the use of
estimates and assumptions including cash flows associated with proved plus probable oil and gas reserves, the discount rate used
to present value future cash flows, and assumptions regarding the timing and amount of capital expenditures and future
abandonment and reclamation obligations. Any changes to these estimates and assumptions could impact the calculation of the
recoverable amount and the carrying value of assets.
Exploration and Evaluation ("E&E") Assets
Costs associated with acquiring oil and natural gas licenses and exploratory drilling are accumulated as E&E assets pending
determination of technical feasibility and commercial viability. The determination of technical feasibility and commercial viability of
E&E assets for the purposes of reclassifying such assets to oil and gas properties is subject to management judgment.
Management uses the establishment of commercial reserves as the basis for determining technical feasibility and commercial
viability. Upon determination of commercial reserves, E&E assets are tested for impairment and reclassified to oil and natural gas
properties.
Asset Retirement Obligations
The Company's provision for asset retirement obligations is based on estimated costs to abandon and reclaim the wells and the
facilities, the estimated time period during which these costs will be incurred in the future, and discount and inflation rates. The
provision for asset retirement obligations represents management's best estimate of the present value of the future abandonment
and reclamation costs required under current regulatory requirements. Actual abandonment and reclamation costs could be
materially different from estimated amounts.
Income Taxes
Regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change.
Interpretation and application of existing regulation and legislation requires management judgment. Income tax filings are subject to
audit and re-assessment and changes in facts, circumstances and interpretations of the standards may result in a material change
to the Company's provision for income taxes. Estimates of future income taxes are subject to measurement uncertainty.
CHANGES IN SIGNIFICANT ACCOUNTING POLICIES
Business Combinations
Baytex adopted amendments to IFRS 3 Business Combinations effective January 1, 2020, which will be applied prospectively to
acquisitions that occur on or after January 1, 2020. These amendments did not result in changes to the Company's accounting
policies for applying the acquisition method but could result in future acquisitions being accounted for as an asset acquisition as
opposed to a business combination.
NYSE LISTING
On March 24, 2020 we received notice from the New York Stock Exchange (“NYSE”) that Baytex was no longer in compliance with
one of the NYSE’s continued listing standards because the average closing price of Baytex’s common shares was less than
US$1.00 per share over a consecutive 30-day trading period. Baytex did not regain compliance and its common shares were
delisted from the NYSE on December 3, 2020.
Baytex's common share remain registered with the U.S. Securities and Exchange Commission. However, provided that Baytex
remains listed on the TSX and the average daily trading volume of Baytex’s common shares in the U.S. is less than 5% of Baytex’s
worldwide average daily trading volume over the 12-month period following the delisting, Baytex may be eligible to deregister its
common shares at that time. Deregistration of Baytex's common shares would terminate its reporting obligations under the
Securities Exchange Act of 1934, as amended.
Baytex Energy Corp. 2020 Annual Report
31
NON-GAAP AND CAPITAL MEASUREMENT MEASURES
In this MD&A, we refer to certain capital management measures (such as adjusted funds flow, exploration and development
expenditures, free cash flow, net debt, operating netback and Bank EBITDA) which do not have any standardized meaning
prescribed by Canadian Generally Accepted Accounting Principles ("GAAP"). While adjusted funds flow, exploration and
development expenditures, free cash flow, net debt, operating netback and Bank EBITDA are commonly used in the oil and natural
gas industry, our determination of these measures may not be comparable with calculations of similar measures presented by other
reporting issuers. We believe that inclusion of these non-GAAP financial measures provide useful information to investors and
shareholders when evaluating the financial results of the Company.
Adjusted Funds Flow
We consider adjusted funds flow a key measure that provides a more complete understanding of operating performance and our
ability to generate funds for exploration and development expenditures, debt repayment, settlement of our abandonment
obligations and potential future dividends. In addition, we use a ratio of net debt to adjusted funds flow to manage our capital
structure. We eliminate settlements of abandonment obligations from cash flow from operations as the amounts can be
discretionary and may vary from period to period depending on our capital programs and the maturity of our operating areas. The
settlement of abandonment obligations are managed with our capital budgeting process which considers available adjusted funds
flow. Changes in non-cash working capital are eliminated in the determination of adjusted funds flow as the timing of collection,
payment and incurrence is variable and by excluding them from the calculation we are able to provide a more meaningful measure
of our operations on a continuing basis.
Adjusted funds flow should not be construed as an alternative to performance measures determined in accordance with GAAP,
such as cash flow from operating activities and net income or loss.
The following table reconciles cash flow from operating activities to adjusted funds flow.
($ thousands)
Cash flow from operating activities
Change in non-cash working capital
Asset retirement obligations settled
Adjusted funds flow
Exploration and Development Expenditures
Years Ended December 31
2020
353,096 $
(48,758)
7,168
311,506 $
2019
834,939
52,070
15,417
902,426
$
$
We use exploration and development expenditures to measure and evaluate the performance of our capital programs. The total
amount of exploration and development expenditures is managed as part of our budgeting process and can vary from period to
period depending on the availability of adjusted funds flow and other sources of liquidity. We eliminate changes in non-cash
working capital, acquisition and dispositions, and additions to other plant and equipment from investing activities as these amounts
are generated by activities outside of our programs to explore and develop our existing properties.
Changes in non-cash working capital are eliminated in the determination of exploration and development expenditures as the
timing of collection, payment and incurrence is variable and by excluding them from the calculation we are able to provide a more
meaningful measure of our operations on a continuing basis. Our capital budgeting process is focused on programs to explore and
develop our existing properties, accordingly, cash flows arising from acquisition and disposition activities are eliminated as we
analyze these activities on a transaction by transaction basis separately from our analysis of the performance of our capital
programs. Additions to other plant and equipment is primarily comprised of expenditures on corporate assets which do not
generate incremental oil and natural gas production and are therefore analyzed separately from our evaluation of the performance
of our exploration and development programs.
32
Baytex Energy Corp. 2020 Annual Report
The following table reconciles cash flow used in investing activities to exploration and development expenditures.
($ thousands)
Cash flow used in investing activities
Change in non-cash working capital
Proceeds from dispositions
Property acquisitions
Additions to other plant and equipment
Exploration and development expenditures
Free Cash Flow
Years Ended December 31
2020
314,469 $
(32,031)
182
—
(2,280)
280,340 $
2019
617,508
(62,485)
1,487
(3,667)
(552)
552,291
$
$
We define free cash flow as adjusted funds flow less exploration and development expenditures (both non-GAAP measures
defined above), payments on lease obligations and asset retirement obligations settled. We use free cash flow to evaluate funds
available for debt repayment, common share repurchases, potential future dividends and acquisition opportunities.
The following table provides our computation of free cash flow.
($ thousands)
Adjusted funds flow
Exploration and development expenditures
Payments on lease obligations
Asset retirement obligations settled
Free cash flow
Net Debt
Years Ended December 31
2020
311,506 $
(280,340)
(5,925)
(7,168)
18,073 $
2019
902,426
(552,291)
(5,956)
(15,417)
328,762
$
$
We believe that net debt assists in providing a more complete understanding of our financial position and provides a key measure
to assess our liquidity. We calculate net debt based on the principal amounts of our credit facilities and long-term notes
outstanding, including trade and other payables, cash, and trade and other receivables. We use the principal amounts of the credit
facilities and long-term notes outstanding in the calculation of net debt as these amounts represent our total repayment obligation
at maturity. The carrying amount of debt issue costs associated with the credit facilities and long-term notes are excluded on the
basis that these amounts have already been paid by Baytex at inception of the contract and do not represent an additional source
of liquidity or repayment obligation.
The following table summarizes our calculation of net debt.
($ thousands)
Credit facilities (1)
Long-term notes (1)
Trade and other payables
Cash
Trade and other receivables
Net debt
(1) Principal amount of instruments expressed in Canadian dollars.
December 31, 2020
December 31, 2019
$
$
651,173 $
1,147,950
155,955
—
(107,477)
1,847,601 $
506,471
1,337,200
207,454
(5,572)
(173,762)
1,871,791
Baytex Energy Corp. 2020 Annual Report
33
Operating Netback
We define operating netback as petroleum and natural gas sales, less blending expense, royalties, operating expense and
transportation expense. Operating netback per boe is the operating netback divided by barrels of oil equivalent production volume
for the applicable period. We believe that this measure assists in assessing our ability to generate cash margin on a unit of
production basis and is a key measure used to evaluate our operating performance.
($ thousands)
Petroleum and natural gas sales
Blending and other expense
Total sales, net of blending and other expense
Royalties
Operating expense
Transportation expense
Operating netback
Realized financial derivatives gain
$
Years Ended December 31
2020
975,477 $
(48,381)
927,096
(163,735)
(331,345)
(28,437)
403,579
47,836
2019
1,805,919
(68,795)
1,737,124
(320,241)
(397,716)
(43,942)
975,225
75,620
Operating netback after realized financial derivatives
$
451,415 $
1,050,845
Bank EBITDA
Bank EBITDA is used to assess compliance with certain financial covenants contained in our credit facility agreements. Net income
is adjusted for the items set forth in the table below as prescribed by the credit facility agreements. The following table reconciles
net income or loss to Bank EBITDA on a twelve-month rolling basis.
($ thousands)
Net income (loss)
Plus:
Financing and interest
Unrealized foreign exchange loss (gain)
Unrealized financial derivatives loss
Current income tax expense
Deferred income tax recovery
Depletion and depreciation
Gain on dispositions
Impairment
Non-cash items (1)
Bank EBITDA
Years Ended December 31
2020
$
(2,438,964) $
125,441
9,232
18,500
574
(160,967)
486,380
(901)
2,360,220
15,339
2019
(12,459)
125,865
(62,753)
82,817
2,093
(68,555)
731,686
(2,238)
187,822
27,048
$
414,854 $
1,011,326
(1) Non-cash items include share-based compensation, exploration and evaluation expense, note redemption premiums, interest on lease
obligations, and non-cash other income.
CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
As of December 31, 2020, an evaluation was conducted of the effectiveness of our “disclosure controls and procedures” (as
defined in the United States by Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)
and in Canada by National Instrument 52-109, Certification of Disclosure in Issuers' Annual and Interim Filings ("NI 52-109")) under
the supervision of and with the participation of management, including the President and Chief Executive Officer and the Executive
Vice President and Chief Financial Officer of Baytex (collectively the "certifying officers"). Based on that evaluation, the certifying
officers concluded that our disclosure controls and procedures are effective to ensure that the information required to be disclosed
in the reports that we file or submit under the Exchange Act or under Canadian securities legislation is (i) recorded, processed,
summarized and reported within the time periods specified in the applicable rules and forms and (ii) accumulated and
communicated to our management, including the certifying officers, to allow timely decisions regarding the required disclosure.
34
Baytex Energy Corp. 2020 Annual Report
It should be noted that while the certifying officers believe that our disclosure control and procedures provide a reasonable level of
assurance that they are effective, they do not expect that our disclosure controls and procedures will prevent all errors and fraud. A
control system, no matter how well conceived or operated, can provide only reasonable, not absolute assurance that the objectives
of the control system are met.
Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over the Company's financial reporting.
Internal control over our financial reporting is a process designed under the supervision of and with the participation of
management, including the certifying officers, to provide reasonable assurance regarding the reliability of financial reporting and
the preparation of financial statements.
Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even those
systems determined to be effective can provide only reasonable assurance with respect to the financial statement preparation and
presentation.
Management has assessed the effectiveness of our "internal control over financial reporting" as defined in Rules 13a-15(f) and
15d-15(f) of the Exchange Act and as defined by NI 52-109. The assessment was based on the framework in Internal Control -
Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management
concluded that our internal control over financial reporting was effective as of December 31, 2020.
The effectiveness of our internal control over financial reporting as of December 31, 2020 has been audited by KPMG LLP, an
independent registered public accounting firm, as stated in their Report of Independent Registered Public Accounting Firm.
Changes in Internal Control over Financial Reporting
No changes were made to our internal control over financial reporting during the year ended December 31, 2020 that have
materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.
SELECTED ANNUAL INFORMATION
The following table summarizes key annual financial and operating information over the three most recently completed financial
years.
($ thousands, except per common share amounts)
Revenues, net of royalties
Adjusted funds flow
Per common share - basic
Per common share - diluted
Net income (loss)
Per common share - basic
Per common share - diluted
Total assets
Credit facilities - principal
Long term notes - principal
Average wellhead prices, net of blending costs ($/boe)
Total production (boe/d)
$
$
$
$
$
$
$
$
$
$
$
2020
811,742 $
311,506 $
0.56 $
0.56 $
2019
2018
1,485,678 $
1,115,116
902,426 $
472,983
1.62 $
1.62 $
1.35
1.35
(2,438,964) $
(12,459) $
(325,309)
(4.35) $
(4.35) $
(0.02) $
(0.02) $
(0.93)
(0.93)
3,408,096 $
5,914,083 $
6,377,198
651,173 $
506,471 $
522,294
1,147,950 $
1,337,200 $
1,596,323
31.75 $
79,781
48.72 $
97,680
46.31
80,458
Baytex Energy Corp. 2020 Annual Report
35
FORWARD-LOOKING STATEMENTS
In the interest of providing our shareholders and potential investors with information regarding Baytex, including management's
assessment of the Company’s future plans and operations, certain statements in this document are "forward-looking statements"
within the meaning of the United States Private Securities Litigation Reform Act of 1995 and "forward-looking information" within
the meaning of applicable Canadian securities legislation (collectively, "forward-looking statements"). In some cases, forward-
looking statements can be identified by terminology such as "anticipate", "believe", "continue", "could", "estimate", "expect",
"forecast", "intend", "may", "objective", "ongoing", "outlook", "potential", "plan", "project", "should", "target", "would", "will" or similar
words suggesting future outcomes, events or performance. The forward-looking statements contained in this document speak only
as of the date of this document and are expressly qualified by this cautionary statement.
Specifically, this document contains forward-looking statements relating to but not limited to: our business strategies, plans and
objectives; our capital budget and expected average daily production for 2021; our expected royalty rate and operating,
transportation, general and administrative and interest expenses for 2021; our expected lease expenditures and asset retirement
obligations settled in 2021; the existence, operation and strategy of our risk management program; the reassessment of our tax
filings by the Canada Revenue Agency; our intention to defend the reassessments; our view of our tax filing position; the length of
time it would take to resolve the reassessments; that we would owe cash taxes and late payment interest if the reassessment is
successful; that our internally generated adjusted funds flow and our existing undrawn credit facilities will provide sufficient liquidity
to sustain our operations and planned capital expenditures; that we may issue or repurchase debt or equity securities from time to
time or sell assets; our intent to fund certain financial obligations with cash flow from operations and the expected timing of the
financial obligations; our plans with respect to asset retirement obligation activities; and that we may be eligible to deregister our
common shares under the Securities Exchange Act of 1934. In addition, information and statements relating to reserves are
deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that
the reserves described exist in quantities predicted or estimated, and that the reserves can be profitably produced in the future.
These forward-looking statements are based on certain key assumptions regarding, among other things: petroleum and natural gas
prices and differentials between light, medium and heavy oil prices; well production rates and reserve volumes; our ability to add
production and reserves through our exploration and development activities; capital expenditure levels; our ability to borrow under
our credit agreements; the receipt, in a timely manner, of regulatory and other required approvals for our operating activities; the
availability and cost of labour and other industry services; interest and foreign exchange rates; the continuance of existing and, in
certain circumstances, proposed tax and royalty regimes; our ability to develop our crude oil and natural gas properties in the
manner currently contemplated; and current industry conditions, laws and regulations continuing in effect (or, where changes are
proposed, such changes being adopted as anticipated). Readers are cautioned that such assumptions, although considered
reasonable by Baytex at the time of preparation, may prove to be incorrect.
Actual results achieved will vary from the information provided herein as a result of numerous known and unknown risks and
uncertainties and other factors. Such factors include, but are not limited to: the volatility of oil and natural gas prices and price
differentials (including the impacts of Covid-19); the availability and cost of capital or borrowing; risks associated with our ability to
exploit our properties and add reserves; availability and cost of gathering, processing and pipeline systems; that our credit facilities
may not provide sufficient liquidity or may not be renewed; failure to comply with the covenants in our debt agreements; risks
associated with a third-party operating our Eagle Ford properties; public perception and its influence on the regulatory regime;
restrictions or costs imposed by climate change initiatives and the physical risks of climate change; new regulations on hydraulic
fracturing; restrictions on or access to water or other fluids; changes in government regulations that affect the oil and gas industry;
regulations regarding the disposal of fluids; changes in environmental, health and safety regulations; costs to develop and operate
our properties; variations in interest rates and foreign exchange rates; risks associated with our hedging activities; retaining or
replacing our leadership and key personnel; changes in income tax or other laws or government incentive programs; uncertainties
associated with estimating oil and natural gas reserves; our inability to fully insure against all risks; risks of counterparty default;
risks related to our thermal heavy oil projects; alternatives to and changing demand for petroleum products; risks associated with
our use of information technology systems; results of litigation; risks associated with large projects; risks associated with the
ownership of our securities, including changes in market-based factors; risks for United States and other non-resident
shareholders, including the ability to enforce civil remedies, differing practices for reporting reserves and production, additional
taxation applicable to non-residents and foreign exchange risk; and other factors, many of which are beyond our control. These and
additional risk factors are discussed in our Annual Information Form, Annual Report on Form 40-F and Management's Discussion
and Analysis for the year ended December 31, 2020, to be filed with Canadian securities regulatory authorities and the U.S.
Securities and Exchange Commission not later than March 31, 2021 and in our other public filings.
The above summary of assumptions and risks related to forward-looking statements has been provided in order to provide
shareholders and potential investors with a more complete perspective on Baytex’s current and future operations and such
information may not be appropriate for other purposes.
There is no representation by Baytex that actual results achieved will be the same in whole or in part as those referenced in the
forward-looking statements and Baytex does not undertake any obligation to update publicly or to revise any of the included
forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by
applicable securities law.
36
Baytex Energy Corp. 2020 Annual Report
RISK FACTORS
We are focused on long-term strategic planning and have identified key risks, uncertainties and opportunities associated with our
business that can impact the financial and operational results. Listed below is a description of these risks and uncertainties.
Volatility of oil and natural gas prices and price differentials
Our financial condition is substantially dependent on, and highly sensitive to, the prevailing prices of crude oil and natural gas. Low
prices for crude oil and natural gas produced by us could have a material adverse effect on our operations, financial condition and
the value and amount of our reserves.
Prices for crude oil and natural gas fluctuate in response to changes in the supply of, and demand for, crude oil and natural gas,
market uncertainty and a variety of additional factors beyond our control. Crude oil prices are primarily determined by international
supply and demand. Factors which affect crude oil prices include the actions of OPEC, OPEC+, the condition of the Canadian,
United States, European and Asian economies (including conditions resulting from the impact of the COVID-19), government
regulation, political stability in the Middle East and elsewhere, the supply of crude oil in North America and internationally, the ability
to secure adequate transportation for products, the availability of alternate fuel sources and weather conditions. Natural gas prices
realized by us are affected primarily in North America by supply and demand, weather conditions, industrial demand, prices of
alternate sources of energy and developments related to the market for liquefied natural gas. All of these factors are beyond our
control and can result in a high degree of price volatility. Fluctuations in currency exchange rates further compound this volatility
when commodity prices, which are generally set in U.S. dollars, are stated in Canadian dollars.
Our financial performance also depends on revenues from the sale of commodities which differ in quality and location from
underlying commodity prices quoted on financial exchanges. Of particular importance are the price differentials between our light/
medium oil and heavy oil (in particular the light/heavy differential) and quoted market prices. Not only are these discounts
influenced by regional supply and demand factors, they are also influenced by other factors such as transportation costs, capacity
and interruptions, refining demand, storage capacity, the availability and cost of diluents used to blend and transport product and
the quality of the oil produced, all of which are beyond our control. In addition, there is not sufficient pipeline capacity for Canadian
crude oil to access the American refinery complex or tidewater to access world markets and the availability of additional transport
capacity via rail is more expensive and variable, therefore, the price for Canadian crude oil is very sensitive to pipeline and refinery
outages, which contributes to this volatility.
Decreases to or prolonged periods of low commodity prices, particularly for oil, may negatively impact our ability to meet guidance
targets, maintain our business and meet all of our financial obligations as they come due. It could also result in the shut-in of
currently producing wells without an equivalent decrease in expenses due to fixed costs, a delay or cancellation of existing or future
drilling, development or construction programs, un-utilized long-term transportation commitments and a reduction in the value and
amount of our reserves.
We conduct assessments of the carrying value of our assets in accordance with Canadian GAAP. If crude oil and natural gas
forecast prices change, the carrying value of our assets could be subject to revision and our net earnings could be adversely
affected.
Availability and cost of capital or borrowing to maintain and/or fund future development and acquisitions
The future development of our business may be dependent on our ability to obtain additional capital including, but not limited to,
debt and equity financing. Unpredictable financial markets and the associated credit impacts may impede our ability to secure and
maintain cost effective financing and limit our ability to achieve timely access to capital on acceptable terms and conditions. If
external sources of capital become limited or unavailable, our ability to make capital investments, continue our business plan, meet
all of our financial obligations as they come due and maintain existing properties may be impaired.
Our ability to obtain additional capital is dependent on, among other things, a general interest in energy industry investments and,
in particular, interest in our securities along with our ability to maintain our credit ratings. If we are unable to maintain our
indebtedness and financial ratios at levels acceptable to our credit rating agencies, or should our business prospects deteriorate,
our credit ratings could be downgraded. This would adversely affect the value of our outstanding securities and existing debt and
our ability to obtain new financing, and may increase our borrowing costs.
From time to time we may enter into transactions which may be financed in whole or in part with debt or equity. The level of our
indebtedness from time to time, could impair our ability to obtain additional financing on a timely basis to take advantage of
business opportunities that may arise. Additionally, from time to time, we may issue securities from treasury in order to reduce debt,
complete acquisitions and/or optimize our capital structure.
Our success is highly dependent on our ability to exploit existing properties and add to our oil and natural gas reserves
Our oil and natural gas reserves are a depleting resource and decline as such reserves are produced, as a result, our long-term
commercial success depends on our ability to find, acquire, develop and commercially produce oil and natural gas reserves. The
business of exploring for, developing or acquiring reserves is capital intensive. If external sources of capital become limited or
unavailable on commercially reasonable terms, our ability to make the necessary capital investments to maintain or expand our oil
and natural gas reserves may be impaired. Future oil and natural gas exploration may involve unprofitable efforts, not only from
unsuccessful wells, but also from wells that are productive but do not produce sufficient petroleum substances to return a profit.
Completion of a well does not assure a profit on the investment. Drilling hazards or environmental liabilities or damages could
Baytex Energy Corp. 2020 Annual Report
37
greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful
wells. These conditions include delays or failure in obtaining governmental approvals or consents, shut-ins of connected wells
resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical
conditions. While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over
time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely
affect revenue and cash flow from operating activities to varying degrees.
There is no assurance we will be successful in developing our reserves or acquiring additional reserves at acceptable costs.
Without these reserves additions, our reserves will deplete and as a consequence production from and the average reserve life of
our properties will decline, which may adversely affect our business, financial condition, results of operations and prospects.
The amount of oil and natural gas that we can produce and sell is subject to the availability and cost of gathering,
processing and pipeline systems
We deliver our products through gathering, processing and pipeline systems which we do not own and purchasers of our products
rely on third party infrastructure to deliver our products to market. The lack of access to capacity in any of the gathering, processing
and pipeline systems could result in our inability to realize the full economic potential of our production or in a reduction of the price
offered for our production. Alternately, a substantial decrease in the use of such systems can increase the cost we incur to use
them. Any significant change in market factors or other conditions affecting these infrastructure systems and facilities, as well as
any delays in constructing new infrastructure systems and facilities, could harm our business and, in turn, our financial condition. A
significant change may result from the conversion of most of the capacity on the Enbridge mainline from the common carrier model,
which will end on July 1, 2021, to a contracted service model, where only shippers who sign long term transportation agreements
will have access.
Access to the pipeline capacity for the export of crude oil from Canada has, at times, been inadequate for the amount of Canadian
production being exported. This has resulted in significantly lower prices being realized by Canadian producers compared with the
WTI price and the Brent price for crude oil. Although pipeline expansions are ongoing, the lack of pipeline capacity continues to
affect the oil and natural gas industry in Canada and limit the ability to produce and obtain global benchmark pricing for oil and
natural gas production. In addition, the pro-rationing of capacity on inter-provincial pipeline systems also continues to affect the
ability to export oil and natural gas from Canada. There can be no certainty that investment in pipelines, which would result in
additional long-term take-away capacity, will be made by applicable third party pipeline providers or that any requisite applications
will receive regulatory approval. There is also no certainty that short-term operational constraints on pipeline systems, arising from
pipeline interruption and/or increased supply of crude oil, will not occur.
There is no certainty that crude-by-rail transportation and other alternative types of transportation for our production will be
sufficient to address any gaps caused by operational constraints on pipeline systems. In addition, our crude-by-rail shipments may
be impacted by service delays, inclement weather, derailment or blockades and could adversely impact our crude oil sales volumes
or the price received for our product. Crude oil produced and sold by us may be involved in a derailment or incident that results in
legal liability or reputational harm.
A portion of our production may be processed through facilities controlled by third parties. From time to time these facilities may
discontinue or decrease operations either as a result of normal servicing requirements or as a result of unexpected events. A
discontinuance or decrease of operations could materially adversely affect our ability to process our production and to deliver the
same for sale.
Our Credit Facilities may not provide sufficient liquidity and a failure to renew our Credit Facilities at maturity could
adversely affect our financial condition
Our Credit Facilities and any replacement credit facilities may not provide sufficient liquidity. The amounts available under our
Credit Facilities may not be sufficient for future operations, or we may not be able to obtain additional financing on economic terms,
if at all. There can be no assurance that the amount of our Credit Facilities will be adequate for our future financial obligations,
including future capital expenditures, or that we will be able to obtain additional funds. In the event we are unable to refinance our
debt obligations, it may impact our ability to fund ongoing operations. In the event that the Credit Facilities are not extended before
April 2, 2024, indebtedness under the Credit Facilities will be repayable at that time. There is also a risk that the Credit Facilities will
not be renewed for the same amount or on the same terms.
Failure to comply with the covenants in the agreements governing our debt, including our obligation to repay the Senior
Notes at maturity, could adversely affect our financial condition
We are required to comply with the covenants in our Credit Facilities and the Senior Notes. If we fail to comply with such
covenants, are unable to pay, repay or refinance amounts owned at maturity or pay the debt service charges or otherwise commit
an event of default, such as bankruptcy, it could result in the seizure and/or sale of our assets by our creditors. The proceeds from
any sale of our assets would be applied to satisfy amounts owed to the secured creditors and then unsecured creditors. Only after
the proceeds of that sale were applied towards our debt would the remainder, if any, be available for the benefit of our
Shareholders.
38
Baytex Energy Corp. 2020 Annual Report
We are not the operator of our drilling locations in our Eagle Ford acreage and, therefore, we will not be able to control
the timing of development, associated costs or the rate of production of that acreage
Marathon Oil is the operator of our Eagle Ford acreage and we are reliant upon Marathon Oil to operate successfully. Marathon Oil
will make decisions based on its own best interest and the collective best interest of all of the working interest owners of this
acreage, which may not be in our best interest. We have a limited ability to exercise influence over the operational decisions of
Marathon Oil, including the setting of capital expenditure budgets and determination of drilling locations and schedules. The
success and timing of development activities, operated by Marathon Oil, will depend on a number of factors that will largely be
outside of our control, including:
•
the timing and amount of capital expenditures;
• Marathon Oil's expertise and financial resources;
approval of other participants in drilling wells;
•
selection of technology; and
•
the rate of production of reserves, if any.
•
To the extent that the capital expenditure requirements related to our Eagle Ford acreage exceeds our budgeted amounts, it may
reduce the amount of capital we have available to invest in our other assets. We have the ability to elect whether or not to
participate in well locations proposed by Marathon Oil on an individual basis. If we elect to not participate in a well location, we
forgo any revenue from such well until Marathon Oil has recouped, from our working interest share of production from such well,
300% to 500% of our working interest share of the cost of such well.
Public perception and its influence on the regulatory regime
Concern over the impact of oil and gas development on the environment and climate change has received considerable attention in
the media and recent public commentary, and the social value proposition of resource development is being challenged.
Additionally, certain pipeline leaks, rail car derailments, major weather events and induced seismicity events have gained media,
environmental and other stakeholder attention. Future laws and regulation may be impacted by such incidents, which could have a
material adverse effect on our financial condition, results of operations or prospects.
Restrictions and/or costs associated with regulatory initiatives to combat climate change and the physical risks of climate
change may have a material adverse affect on our business
Regulatory and Policy Initiatives
Our exploration and production facilities and other operational activities emit GHGs. As such, it is highly likely that GHG emissions
regulation (including carbon taxes) enacted in jurisdictions where we operate will impact us.
Negative consequences which could result from new GHG emissions regulation include, but are not limited to: increased operating
costs, increased construction and development costs, additional monitoring and compliance costs, a requirement to redesign or
retrofit current facilities, permitting delays, additional costs associated with the purchase of emission credits or allowances and
reduced demand for crude oil. Additionally, if GHG emissions regulation differs by region or type of production, all or part of our
production could be subject to costs which are disproportionately higher than those of other producers.
The direct or indirect costs of compliance with GHG emissions regulation may have a material adverse affect on our business,
financial condition, results of operations and prospects. At this time, it is not possible to predict whether compliance costs will have
a material adverse affect our financial condition, results of operations or prospects.
Although we provide for the necessary amounts in our annual capital budget to fund our currently estimated obligations, there can
be no assurance that we will be able to satisfy our actual future obligations associated with GHG emissions from such funds.
Physical Risk
Climate change has been linked to extreme weather conditions. Extreme hot and cold weather, heavy snowfall, heavy rain fall,
hurricanes and wildfires may restrict our ability to access our properties, cause operational difficulties including damage to
machinery and facilities. Extreme weather also increases the risk of personnel injury as a result of dangerous working conditions.
Certain of our assets are located where they are exposed to forest fires, floods, heavy rains, hurricanes and other extreme weather
conditions which can lead to significant downtime, damage to such assets and/or increased costs of construction and maintenance.
Moreover, extreme weather conditions may lead to disruptions in our ability to transport produced oil and natural gas as well as
goods and services in our supply chain.
Baytex Energy Corp. 2020 Annual Report
39
New regulations on hydraulic fracturing may lead to operational delays, increased costs and/or decreased production
volumes
Hydraulic fracturing involves the injection of water, sand and small amounts of additives under pressure into rock formations to
stimulate the production of oil and natural gas. Specifically, hydraulic fracturing enables the production of commercial quantities of
oil and natural gas from reservoirs that were previously unproductive. Hydraulic fracturing has featured prominently in recent
political, media and activist commentary on the subject of water usage, induced seismicity events and environmental damage. Any
new laws, regulations or permitting requirements regarding hydraulic fracturing could lead to operational delays, increased
operating costs, third party or governmental claims, and could increase the Corporation's costs of compliance and doing business
as well as delay the development of oil and natural gas resources from shale formations, which are not commercial without the use
of hydraulic fracturing. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are
ultimately able to produce from our reserves.
Regulatory water use restrictions and/or limited access to water or other fluids may impact the Corporation's ability to
fracture its wells or carry out waterflood operations
The Corporation undertakes or intends to undertake certain hydraulic fracturing, SAGD, CCS and waterflooding programs. To
undertake such operations the Corporation needs to have access to sufficient volumes of water, or other liquids. There is no
certainty that the Corporation will have access to the required volumes of water. In addition, in certain areas there may be
restrictions on water use for activities such as hydraulic fracturing, SAGD, CCS and waterflooding. If the Corporation is unable to
access such water it may not be able to undertake hydraulic fracturing, SAGD, CCS or waterflooding activities, which may reduce
the amount of oil and natural gas that the Corporation is ultimately able to produce from its reserves.
Changes in government controls, legislation or regulations that affect the oil and gas industry, or failing to comply with
such controls, legislation or regulations, could adversely affect us
The oil and gas industry is subject to extensive controls and regulations governing its operations (including land tenure, exploration,
development, production, refining, transportation, and marketing) imposed by legislation enacted by various levels of government
and, with respect to pricing and taxation of oil and natural gas, by agreements among the governments of Canada, Alberta,
Saskatchewan, the United States and Texas, all of which should be carefully considered by investors in the oil and gas industry. All
such controls, regulations and legislation are subject to revocation, amendment or administrative change, some of which have
historically been material and in some cases materially adverse and there can be no assurance that there will not be further
revocation, amendment or administrative change which will be materially adverse to our assets, reserves, financial condition,
results of operations or prospects.
The oil and gas industry is also subject to regulation by governments in such matters as the awarding or acquisition of exploration
and production rights, oil sands or other interests, the imposition of specific drilling obligations, environmental protection controls,
control over the development and abandonment of fields (including restrictions on production) and possibly expropriation or
cancellation of contract rights.
Other government controls, legislation or regulations may change from time to time in response to economic or political conditions.
The exercise of discretion by governmental authorities under existing controls, legislation or regulations, the implementation of new
controls, legislation or regulations or the modification of existing controls, legislation or regulations affecting the oil and gas industry
could reduce demand for crude oil and natural gas, increase our costs, or delay or restrict our operations, all of which would have a
material adverse effect on us. In addition, failure to comply with government controls, legislation or regulations may result in the
suspension, curtailment or termination of operations and subject us to liabilities and administrative, civil and criminal penalties.
Compliance costs can be significant.
In addition to regulatory requirements pertaining to the production, marketing and sale of oil and natural gas mentioned above, our
business and financial condition could be influenced by federal legislation affecting, in particular, foreign investment, through
legislation such as the Competition Act (Canada) and the Investment Canada Act (Canada) and the Hart-Scott-Rodino Antitrust
Improvements Act in the United States.
Regulations regarding the disposal of fluids used in the Corporation's operations may increase its costs of compliance or
subject it to regulatory penalties or litigation
The safe disposal of hydraulic fracturing fluids (including the additives) and water recovered from oil and natural gas wells is
subject to ongoing regulatory review by the federal, provincial and state governments, including its effect on fresh water supplies
and the ability of such water to be recycled, amongst other things. While it is difficult to predict the impact of any regulations that
may be enacted in response to such review, the implementation of stricter regulations may increase the Corporation's costs of
compliance.
40
Baytex Energy Corp. 2020 Annual Report
The oil and gas industry is highly regulated and changes in environmental, health and safety controls, legislation or
regulations may impose restrictions, costs or other liabilities
All phases of our operations are subject to environmental, health and safety regulation pursuant to a variety of Canadian, U.S. and
other federal, provincial, state and municipal laws and regulations (collectively, "environmental regulations") governing
occupational health and safety aspects of our operations, the spill, release or emission of materials into the environment or
otherwise relating to environmental protection. Environmental regulations require that wells, facility sites and other properties
associated with our operations be constructed, operated, maintained, abandoned and reclaimed to the satisfaction of applicable
regulatory authorities. In addition, certain types of operations, including exploration and development projects and changes to
certain existing projects, may require the submission and approval of environmental impact assessments or permit applications.
Environmental regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation,
handling, use, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills,
releases and emissions of various substances to the environment. It also imposes restrictions, liabilities and obligations in
connection with the management of fresh or potable water sources that are being used, or whose use is contemplated, in
connection with oil and gas operations. The jurisdictions where we operate have developed liability management programs
designed to prevent taxpayers from incurring costs associated with suspension, abandonment, remediation and reclamation of
wells, facilities and pipelines in the event that a licensee or permit holder becomes defunct. Changes to the requirements of liability
management programs may result in significant increases to the security that must be posted, the timing of our abandonment and
reclamation operations and the costs associated with such operations.
Compliance with environmental regulations can require significant expenditures, including expenditures for clean-up costs and
damages arising out of contaminated properties. Failure to comply with environmental regulations may result in the imposition of
administrative, civil and criminal penalties or issuance of clean up orders in respect of us or our properties, some of which may be
material. We may also be exposed to civil liability for environmental matters or for the conduct of third parties, including private
parties commencing actions and new theories of liability, regardless of negligence or fault. Although it is not expected that the costs
of complying with environmental regulations will have a material adverse effect on our financial condition or results of operations,
no assurance can be made that the costs of complying with environmental regulations in the future will not have such an effect. The
implementation of new environmental regulations or the modification of existing environmental regulations affecting the oil and gas
industry generally could reduce demand for crude oil and natural gas, resulting in stricter standards and enforcement, larger
penalties and liability and increased capital expenditures and operating costs, which could have a material adverse effect on our
financial condition, results of operations or prospects.
Our financial performance is significantly affected by the cost of developing and operating our assets
Our development and operating costs are affected by a number of factors including, but not limited to: price inflation, scheduling
delays, trucking and fuel costs, failure to maintain quality construction standards, the cost of new technologies, supply chain
disruptions and access to skilled labour. Natural gas, electricity, water, diluent, chemicals, supplies, reclamation, abandonment and
labour costs are examples of operating and other costs that are susceptible to significant fluctuation. Increases to development and
operating costs could have a material adverse effect on our financial condition, results of operations or prospects.
Variations in interest rates and foreign exchange rates could adversely affect our financial condition
There is a risk that interest rates will increase given the current historical low level of interest rates. An increase in interest rates
could result in a significant increase in the amount we pay to service debt and could have an adverse effect on our financial
condition, results of operations and prospects.
World oil prices are quoted in United States dollars and the price received by Canadian producers is therefore affected by the
Canada/U.S. foreign exchange rate that may fluctuate over time. A material increase in the value of the Canadian dollar may
negatively impact our revenues. A substantial portion of our operations and production are in the United States and, as such, we
are exposed to foreign currency risk on both revenues and costs to the extent the value of the Canadian dollar decreases relative
to the U.S. dollar. In addition, we are exposed to foreign currency risk as a large portion of our indebtedness is denominated in U.S.
dollars and the interest payable thereon is payable in U.S. dollars. Future Canada/U.S. foreign exchange rates could also impact
the future value of our reserves as determined by our independent evaluator.
A decline in the value of the Canadian dollar relative to the United States dollar provides a competitive advantage to United States
companies acquiring Canadian oil and gas properties and may make it more difficult for us to replace reserves through
acquisitions.
Baytex Energy Corp. 2020 Annual Report
41
Our hedging activities may negatively impact our income and our financial condition
In response to fluctuations in commodity prices, foreign exchange and interest rates, we may utilize various derivative financial
instruments and physical sales contracts to manage our exposure under a hedging program. The terms of these arrangements
may limit the benefit to us of favourable changes in these factors, including receiving less than the market price for our production,
and may also result in us paying royalties at a reference price which is higher than the hedged price. We may also suffer financial
loss due to hedging arrangements if we are unable to produce oil or natural gas to fulfill our delivery obligations. There is also
increased exposure to counterparty credit risk. To the extent that our current hedging agreements are beneficial to us, these
benefits will only be realized for the period and for the commodity quantities in those contracts. In addition, there is no certainty that
we will be able to obtain additional hedges at prices that have an equivalent benefit to us, which may adversely impact our
revenues in future periods.
Failure to retain or replace our leadership and key personnel may have an adverse affect on our business
Our success is dependent upon our management, our leadership capabilities and the quality and competency of our talent. If we
are unable to retain key personnel and critical talent or to attract and retain new talent with the necessary leadership, professional
and technical competencies, it could have a material adverse effect on our financial condition, results of operations and prospects.
Income tax laws or other laws or government incentive programs or regulations relating to our industry may in the future
be changed or interpreted in a manner that adversely affects us and our Shareholders
We file all required income tax returns and believe that we are in full compliance with the applicable tax legislation. However, such
returns are subject to audit and reassessment by the applicable taxation authority. Any such reassessment may have an impact on
current and future taxes payable. At present, the Canadian tax authorities have reassessed the returns of certain of our
subsidiaries.
Tax authorities having jurisdiction over us or our Shareholders may disagree with the manner in which we calculate our income for
tax purposes or could change their administrative practices to our detriment or the detriment of our Shareholders. In addition,
income tax laws and government incentive programs relating to the oil and gas industry may change in a manner that adversely
affects our financial condition, results of operations and prospects.
There are numerous uncertainties inherent in estimating quantities of recoverable oil and natural gas reserves, including
many factors beyond our control
There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our control. In
general, estimates of economically recoverable oil and natural gas reserves and the future net revenues therefrom are based upon
a number of factors and assumptions made as of the date on which the reserves estimates were determined, such as geological
and engineering estimates which have inherent uncertainties, the assumed effects of regulation by governmental agencies,
historical production from the properties, initial production rates, production decline rates, the availability, proximity and capacity of
oil and gas gathering systems, pipelines and processing facilities and estimates of future commodity prices and capital costs, all of
which may vary considerably from actual results.
All such estimates are, to some degree, uncertain and classifications of reserves are only attempts to define the degree of
uncertainty involved. For these reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any
particular group of properties, the classification of such reserves based on risk of recovery and estimates of future net revenues
expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Our
reserves as at December 31, 2020 are estimated using forecast prices and costs. If we realize lower prices for crude oil, natural
gas liquids and natural gas and they are substituted for the estimated price assumptions, the present value of estimated future net
revenues for our reserves and net asset value would be reduced and the reduction could be significant. Our actual production,
revenues, royalties, taxes and development, abandonment and operating expenditures with respect to our reserves will likely vary
from such estimates, and such variances could be material.
Estimates of reserves that may be developed and produced in the future are often based upon volumetric calculations and upon
analogy to similar types of reserves, rather than upon actual production history. Subsequent evaluation of the same reserves based
upon production history will result in variations in the previously estimated reserves and such variances could be material.
Acquiring, developing and exploring for oil and natural gas involves many physical hazards. We have not insured and
cannot fully insure against all risks related to our operations
Our crude oil and natural gas operations are subject to all of the risks normally incidental to the: (i) storing, transporting,
processing, refining and marketing of crude oil, natural gas and other related products; (ii) drilling and completion of crude oil and
natural gas wells; and (iii) operation and development of crude oil and natural gas properties, including, but not limited to:
encountering unexpected formations or pressures, premature declines of reservoir pressure or productivity, blowouts, fires,
explosions, equipment failures and other accidents, gaseous leaks, uncontrollable or unauthorized flows of crude oil, natural gas or
well fluids, migration of harmful substances, oil spills, corrosion, adverse weather conditions, pollution, acts of vandalism, theft and
terrorism and other adverse risks to the environment.
42
Baytex Energy Corp. 2020 Annual Report
Although we maintain insurance in accordance with customary industry practice, we are not fully insured against all of these risks
nor are all such risks insurable and in certain circumstances we may elect not to obtain insurance to deal with specific risks due to
the high premiums associated with such insurance or other reasons. In addition, the nature of these risks is such that liabilities
could exceed policy limits, in which event we could incur significant costs that could have a material adverse effect on our
business, financial condition, results of operations and prospects.
We are subject to risk of default by the counterparties to our contracts and our counterparties may deem us to be a
default risk
We are subject to the risk that counterparties to our risk management contracts, marketing arrangements and operating
agreements and other suppliers of products and services may default on their obligations under such agreements or arrangements,
including as a result of liquidity requirements or insolvency. Furthermore, low oil and natural gas prices increase the risk of bad
debts related to our joint venture and industry partners. A failure by such counterparties to make payments or perform their
operational or other obligations to us may adversely affect our results of operations, cash flow from operating activities and
financial position. Conversely, our counterparties may deem us to be at risk of defaulting on our contractual obligations. These
counterparties may require that we provide additional credit assurances by prepaying anticipated expenses or posting letters of
credit, which would decrease our available liquidity and increase our costs.
Our thermal heavy oil projects face additional risks compared to conventional oil and gas production
Our thermal heavy oil projects are capital intensive projects which rely on specialized production technologies. Certain current
technologies for the recovery of heavy oil, such as CSS and SAGD, are energy intensive, requiring significant consumption of
natural gas and other fuels in the production of steam that is used in the recovery process. The amount of steam required in the
production process varies and therefore impacts costs. The performance of the reservoir can also affect the timing and levels of
production using new technologies. A large increase in recovery costs could cause certain projects that rely on CSS, SAGD or
other new technologies to become uneconomic, which could have an adverse effect on our financial condition and our reserves.
There are risks associated with growth and other capital projects that rely largely or partly on new technologies and the
incorporation of such technologies into new or existing operations. The success of projects incorporating new technologies cannot
be assured.
Project economics and our earnings may be reduced if increases in operating costs are incurred. Factors which could affect
operating costs include, without limitation: labour costs; the cost of catalysts and chemicals; the cost of natural gas and electricity;
water handling and availability; power outages; produced sand causing issues of erosion, hot spots and corrosion; reliability of
facilities; maintenance costs; the cost to transport sales products; and the cost to dispose of certain by-products.
The adoption of alternatives to and changing demand for petroleum products may have an adverse affect on our business
Conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas and
technological advances in fuel economy and renewable energy could reduce demand for oil and natural gas. Certain jurisdictions
have implemented policies or incentives to decrease the use of fossil fuels and encourage the use of renewable fuel alternatives,
which may lessen demand for petroleum products and put downward pressure on commodity prices. In addition, advancements in
energy efficient products have a similar effect on the demand for oil and gas products. The Corporation cannot predict the impact of
changing demand for oil and natural gas products, and any major changes may have a material adverse effect on the Corporation's
business and financial condition by decreasing its cash flow from operating activities and the value of its assets.
Our information technology systems are subject to certain risks
We utilize a number of information technology systems for the administration and management of our business. If our ability to
access and use these systems is interrupted and cannot be quickly and easily restored then such event could have a material
adverse effect on us. Furthermore, although our information technology systems are considered to be secure, if an unauthorized
party is able to access the systems then such unauthorized access may compromise our business in a materially adverse manner.
Adverse results from litigation may have an adverse affect on our business
In the normal course of our operations, we may become involved in, named as a party to, or be the subject of, various legal
proceedings, including regulatory proceedings, tax proceedings and legal actions. Potential litigation may develop in relation to
personal injuries, property damage, royalties, taxes, land and access rights, environmental issues, natural resource damages and
contract disputes. The outcome with respect to outstanding, pending or future proceedings cannot be predicted with certainty and
may be determined adversely to us and could have a material adverse effect on our assets, liabilities, business, financial condition
and results of operations. Even if we prevail in any such legal proceedings, the proceedings could be costly and time-consuming
and may divert the attention of management and key personnel from business operations, which could have an adverse affect on
our financial condition.
We may participate in larger projects and may have more concentrated risk in certain areas of our operations
We have a variety of exploration, development and construction projects underway at any given time. Project delays may result in
delayed revenue receipts and cost overruns may result in projects being uneconomic. Our ability to complete projects is dependent
on general business and market conditions as well as other factors beyond our control, including the availability of skilled labour
and manpower, the availability and proximity of pipeline capacity and rail terminals, weather, environmental and regulatory matters,
ability to access lands, availability of drilling and other equipment and supplies, and availability of processing capacity.
Baytex Energy Corp. 2020 Annual Report
43
Risks Related to Ownership of our Securities
Changes in market-based factors may adversely affect the trading price of the Common Shares
The market price of our Common Shares is sensitive to a variety of market-based factors including, but not limited to, commodity
prices, interest rates, foreign exchange rates, the decision of certain indices to include our Common Shares and the comparability
of the Common Shares to other securities. Any changes in these market-based factors may adversely affect the trading price of the
Common Shares.
Forward-Looking Information rely upon assumptions which may not prove correct
Shareholders and prospective investors are cautioned not to place undue reliance on our forward-looking information. By its nature,
forward-looking information involves numerous assumptions, known and unknown risks and uncertainties, of both a general and
specific nature, that could cause actual results to differ materially from those suggested by the forward-looking information or
contribute to the possibility that predictions, forecasts or projections will prove to be materially inaccurate.
Certain Risks for United States and other non-resident Shareholders
The ability of investors resident in the United States to enforce civil remedies is limited
We are a corporation incorporated under the laws of the Province of Alberta, Canada, our principal office is located in Calgary,
Alberta and a substantial portion of our assets are located outside the United States. Most of our directors and officers and the
representatives of the experts who provide services to us (such as our auditors and our independent qualified reserves evaluators),
and all or a substantial portion of their assets are located outside the United States. As a result, it may be difficult for investors in
the United States to effect service of process within the United States upon such directors, officers and representatives of experts
who are not residents of the United States or to enforce against them judgments of the United States courts based upon civil
liability under the United States federal securities laws or the securities laws of any state within the United States. There is doubt as
to the enforceability in Canada against us or any of our directors, officers or representatives of experts who are not residents of the
United States, in original actions or in actions for enforcement of judgments of United States courts of liabilities based solely upon
the United States federal securities laws or securities laws of any state within the United States.
Canadian and United States practices differ in reporting reserves and production and our estimates may not be
comparable to those of companies in the United States
We report our production and reserves quantities in accordance with Canadian practices and specifically in accordance with NI
51-101. These practices are different from the practices used to report production and to estimate reserves in reports and other
materials filed with the SEC by companies in the United States.
We incorporate additional information with respect to production and reserves which is either not required to be included or
prohibited under rules of the SEC and practices in the United States. We follow the Canadian practice of reporting gross production
and reserve volumes (before deduction of Crown and other royalties). We also follow the Canadian practice of using forecast prices
and costs when we estimate our reserves, whereas the SEC rules require that a 12-month average price, calculated as the
unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the
reporting period, be utilized.
We have included in this AIF estimates of proved reserves and proved plus probable reserves. Probable reserves have a lower
certainty of recovery than proved reserves. The SEC requires oil and gas issuers in their filings with the SEC to disclose only
proved reserves but permits the optional disclosure of probable reserves. The SEC definitions of proved reserves and probable
reserves are different than NI 51-101; therefore, proved, probable and proved plus probable reserves disclosed in this AIF may not
be comparable to United States standards.
As a consequence of the foregoing, our reserves estimates and production volumes in this AIF may not be comparable to those
made by companies utilizing United States reporting and disclosure standards.
There is additional taxation applicable to non-residents
Tax legislation in Canada may impose withholding or other taxes on the cash dividends, stock dividends or other property
transferred by us to non-resident shareholders. These taxes may be reduced pursuant to tax treaties between Canada and the
non-resident shareholder's jurisdiction of residence. Evidence of eligibility for a reduced withholding rate must be filed by the non-
resident shareholder in prescribed form with their broker (or in the case of registered shareholders, with the transfer agent). In
addition, the country in which the non-resident shareholder is resident may impose additional taxes on such dividends. Any of these
taxes may change from time to time.
44
Baytex Energy Corp. 2020 Annual Report
MANAGEMENT'S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of Baytex Energy Corp. (the "Company") is responsible for establishing and maintaining adequate internal
control over financial reporting. Under the supervision of our President and Chief Executive Officer and our Executive Vice
President and Chief Financial Officer we have conducted an evaluation of the effectiveness of our internal control over financial
reporting based on the Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of
the Treadway Commission ("COSO"). Based on our assessment, we have concluded that as of December 31, 2020, our internal
control over financial reporting was effective.
Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even those
systems determined to be effective can provide only reasonable assurance with respect to the financial statement preparation
and presentation.
The effectiveness of the Company's internal control over financial reporting as of December 31, 2020 has been audited by
KPMG LLP, the Company's Independent Registered Public Accounting Firm, who also audited the Company's consolidated
financial statements for the year ended December 31, 2020.
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS
Management, in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting
Standards Board, has prepared the accompanying consolidated financial statements of the Company. Financial and operating
information presented throughout this Annual Report is consistent with that shown in the consolidated financial statements.
Management is responsible for the integrity of the financial information. Internal control systems are designed and maintained to
provide reasonable assurance that assets are safeguarded from loss or unauthorized use and to produce reliable accounting
records for financial reporting purposes.
KPMG LLP were appointed by the Company's Board of Directors to express an audit opinion on the consolidated financial
statements. Their examination included such tests and procedures, as they considered necessary, to provide a reasonable
assurance that the consolidated financial statements are presented fairly in accordance with IFRS.
The Board of Directors is responsible for ensuring that management fulfills its responsibilities for financial reporting and internal
control. The Board of Directors exercises this responsibility through the Audit Committee, with assistance from the Reserves
Committee regarding the annual review of our petroleum and natural gas reserves. The Audit Committee meets regularly with
management and the Independent Registered Public Accounting Firm to ensure that management's responsibilities are properly
discharged, to review the consolidated financial statements and recommend that the consolidated financial statements be
presented to the Board of Directors for approval. The Audit Committee also considers the independence of KPMG LLP and
reviews their fees. The Independent Registered Public Accounting Firm has access to the Audit Committee without the presence
of management.
Edward D. LaFehr
Rodney D. Gray
President and Chief Executive Officer
Executive Vice President and Chief Financial Officer
Baytex Energy Corp.
Baytex Energy Corp.
February 24, 2021
Baytex Energy Corp. 2020 Annual Report
45
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors of Baytex Energy Corp.
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated statements of financial position of Baytex Energy Corp. (the “Company”) as of
December 31, 2020 and 2019, the related consolidated statements of loss and comprehensive loss, changes in equity, and cash
flows for each of the years then ended, and the related notes (collectively, the consolidated financial statements). In our opinion,
the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of
December 31, 2020 and 2019, and its financial performance and its cash flows for the years then ended, in conformity with
International Financial Reporting Standards as issued by the International Accounting Standards Board.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the Company’s internal control over financial reporting as of December 31, 2020, based on criteria established in
Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission, and our report dated February 24, 2021 expressed an unqualified opinion on the effectiveness of the Company’s
internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the
PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and
the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement,
whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the
consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such
procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial
statements. Our audits also included evaluating the accounting principles used and significant estimates made by management,
as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a
reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial
statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or
disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or
complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated
financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate
opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Assessment of the recoverable amount of of oil and gas properties
As discussed in note 6 to the consolidated financial statements, the Company recorded a total impairment charge of $2,247
million related to the Company’s Conventional, Peace River, Lloydminster, Duvernay, Viking and Eagle Ford cash generating
units (CGUs). The Company identified indicators of impairment as of March 31, 2020 and indicators of impairment reversal as of
December 31, 2020 for each of its CGUs and determined the recoverable amount as of March 31, 2020 and December 31, 2020
of each of the CGUs. The determination of recoverable amount of a CGU involves numerous estimates, including cash flows
associated with estimated proved and probable oil and gas reserves of the CGU (“CGU reserves”) and the discount rate. The
estimation of proved and probable oil and gas reserves involves the expertise of independent reserves evaluators, who take into
consideration assumptions related to forecasted production volumes, royalty, operating and capital costs and commodity prices
(collectively “reserve assumptions”). The Company engages independent reserves evaluators to estimate CGU reserves.
We identified the assessment of the recoverable amount of each of the Company’s CGUs as a critical audit matter. Minor
changes in reserve assumptions and discount rates could have had a significant impact on the estimate of recoverable amounts
and the resulting impairment expense of the CGUs. A high degree of auditor judgment was required to evaluate the Company’s
estimates of CGU reserves, and related reserve assumptions, and the discount rates, which were inputs into the calculation of
recoverable amounts. Additionally, the evaluation of these estimates required involvement of valuation professionals with
specialized skills and knowledge.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested
the operating effectiveness of certain internal controls related to the critical audit matter. This included controls related to the
46
Baytex Energy Corp. 2020 Annual Report
Company’s determination of the recoverable amount of each of the CGUs, including controls over the determination of reserve
assumptions and resulting cash flows of the CGU reserves and determination of the discount rate.
We evaluated the competence, capabilities and objectivity of the independent reserves evaluators engaged by the Company. We
evaluated the methodology used by the independent reserves evaluators to estimate the CGU reserves for compliance with
regulatory standards. We compared the current year actual CGU production volumes, royalty, operating and capital costs to
those estimates used in the prior year estimate of proved reserves by CGU to assess the Company’s ability to accurately
forecast. We assessed the forecasted commodity prices used in the estimate of the CGU reserves by comparing them to those
published by other reserve engineering companies. We assessed the forecasted production volumes and forecasted royalty,
operating and capital costs assumptions used in the current year estimate of the CGU reserves by comparing them to historical
results. We involved valuation professionals with specialized skills and knowledge, who assisted in:
•
•
evaluating the Company’s discount rate, by comparing the discount rate against publicly available market data for
comparable assets and assessing the resulting discount rate
evaluating the Company’s estimate of the aggregate recoverable amount of all CGUs by comparing the implied
enterprise value to publicly available market data.
Impact of estimated oil and gas reserves on depletion expense related to oil and gas properties
As discussed in note 3 to the consolidated financial statements, the Company depletes its oil and gas properties using the unit-
of-production method by depletable area. Under such method, capitalized costs are depleted over estimated proved and
probable oil and gas reserves by depletable area (“area reserves”). As discussed in Note 6 to the consolidated financial
statements, the Company recorded depletion expense related to oil and gas properties of $479 million for the year ended
December 31, 2020. The estimation of area reserves requires the expertise of independent reserves evaluators who take into
consideration reserve assumptions. The Company engages independent reserves evaluators to estimate area reserves.
We identified the assessment of the impact of estimated area reserves on depletion expense related to oil and gas properties as
a critical audit matter. Changes in assumptions used to estimate area reserves could have had a significant impact on the
calculation of depletion expense of the depletable area. A high degree of auditor judgment was required in evaluating the area
reserves, and related reserve assumptions, which were used in the calculation of depletion expense.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested
the operating effectiveness of certain internal controls related to the critical audit matter. This included controls related to the
calculation of depletion expense and the estimation of area reserves and related reserves assumptions.
We assessed the calculation of depletion expense for compliance with regulatory standards. We evaluated the competence,
capabilities and objectivity of the independent reserves evaluators engaged by the Company. We evaluated the methodology
used by the independent reserves evaluators to estimate area reserves for compliance with regulatory standards. We compared
2020 actual area production volumes, royalty, operating and capital costs to those estimates used in the prior year estimate of
proved reserves by area to assess the Company’s ability to accurately forecast. We assessed the forecasted commodity prices
used in the estimate of area reserves by comparing them to those published by other reserves engineering companies. We
assessed the forecasted production volumes and forecasted royalty, operating and capital costs assumptions used in the
estimate of area reserves by comparing them to historical results.
Chartered Professional Accountants
We have served as the Company’s auditor since 2016.
Calgary, Canada
February 24, 2021
Baytex Energy Corp. 2020 Annual Report
47
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors of Baytex Energy Corp.
Opinion on Internal Control Over Financial Reporting
We have audited Baytex Energy Corp.’s (and subsidiaries’) (the “Company”) internal control over financial reporting as of
December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of
Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects,
effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control -
Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the consolidated statements of financial position of the Company as of December 31, 2020 and 2019, the related
consolidated statements of loss and comprehensive loss, changes in equity, and cash flows for the years then ended, and the
related notes (collectively, the consolidated financial statements), and our report dated February 24, 2021 expressed an
unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual
Report on Internal Control over Financial Reporting included in Management’s Discussion and Analysis. Our responsibility is to
express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm
registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal
securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all
material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control
over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we
considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that
(1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions
of the assets of the company; (2) 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 the company are being made only in accordance with authorizations of management and directors of the
company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Chartered Professional Accountants
Calgary, Canada
February 24, 2021
48
Baytex Energy Corp. 2020 Annual Report
Baytex Energy Corp.
Consolidated Statements of Financial Position
(thousands of Canadian dollars)
As at
ASSETS
Current assets
Cash
Trade and other receivables
Financial derivatives
Non-current assets
Exploration and evaluation assets
Oil and gas properties
Other plant and equipment
Lease assets
Deferred income tax asset
LIABILITIES
Current liabilities
Trade and other payables
Financial derivatives
Lease obligations
Asset retirement obligations
Non-current liabilities
Credit facilities
Long-term notes
Lease obligations
Asset retirement obligations
Deferred income tax liability
SHAREHOLDERS’ EQUITY
Shareholders' capital
Contributed surplus
Accumulated other comprehensive income
Deficit
Notes
December 31, 2020
December 31, 2019
$
— $
$
$
$
18
5
6
7
15
18
7
10
8
9
7
10
15
11
107,477
5,057
112,534
191,865
3,077,548
7,996
11,098
7,055 $
3,408,096 $
155,955 $
26,792
4,289
11,820
198,856
649,221
1,132,868
6,787
748,563
93,588
2,829,883
5,729,418
14,345
618,976
(5,784,526)
578,213
5,572
173,762
5,433
184,767
320,210
5,387,889
7,598
13,619
—
5,914,083
207,454
8,668
5,798
11,579
233,499
505,412
1,328,175
8,085
656,395
235,308
2,966,874
5,718,835
17,712
556,224
(3,345,562)
2,947,209
5,914,083
Commitments (note 20)
See accompanying notes to the consolidated financial statements.
$
3,408,096 $
Naveen Dargan
Jennifer A. Maki
Director, Baytex Energy Corp.
Director, Baytex Energy Corp.
Baytex Energy Corp. 2020 Annual Report
49
Baytex Energy Corp.
Consolidated Statements of Loss and Comprehensive Loss
(thousands of Canadian dollars, except per common share amounts)
Years Ended December 31
Notes
2020
2019
14
$
5
5, 6
12
16
18
17
15
13
13
$
$
$
$
975,477 $
(163,735)
811,742
331,345
28,437
48,381
34,268
14,011
486,380
2,360,220
9,469
125,441
(29,336)
8,688
(901)
(5,304)
3,411,099
(2,599,357)
574
(160,967)
(160,393)
(2,438,964) $
62,752
(2,376,212) $
(4.35) $
(4.35) $
560,657
560,657
1,805,919
(320,241)
1,485,678
397,716
43,942
68,795
45,469
11,764
731,686
187,822
15,894
125,865
7,197
(61,787)
(2,238)
(7,526)
1,564,599
(78,921)
2,093
(68,555)
(66,462)
(12,459)
(111,650)
(124,109)
(0.02)
(0.02)
557,048
557,048
Revenue, net of royalties
Petroleum and natural gas sales
Royalties
Expenses
Operating
Transportation
Blending and other
General and administrative
Exploration and evaluation
Depletion and depreciation
Impairments
Share-based compensation
Financing and interest
Financial derivatives (gain) loss
Foreign exchange loss (gain)
Gain on dispositions
Other income
Net loss before income taxes
Income tax expense (recovery)
Current income tax expense
Deferred income tax recovery
Net loss
Other comprehensive income (loss)
Foreign currency translation adjustment
Comprehensive loss
Net loss per common share
Basic
Diluted
Weighted average common shares
Basic
Diluted
See accompanying notes to the consolidated financial statements.
50
Baytex Energy Corp. 2020 Annual Report
Baytex Energy Corp.
Consolidated Statements of Changes in Equity
(thousands of Canadian dollars)
Notes
Shareholders’
capital
Contributed
surplus
Accumulated
other
comprehensive
income
Deficit
Total equity
Balance at December 31, 2018
$
5,701,516 $
19,137 $
667,874 $
(3,333,103) $
3,055,424
Vesting of share awards
Share-based compensation
Comprehensive loss
Balance at December 31, 2019
Vesting of share awards
Share-based compensation
Comprehensive income (loss)
Balance at December 31, 2020
11
12
11
12
17,319
—
—
(17,319)
15,894
—
—
—
—
—
(111,650)
(12,459)
—
15,894
(124,109)
$
5,718,835 $
17,712 $
556,224 $
(3,345,562) $
2,947,209
10,583
(10,583)
—
—
7,216
—
—
—
—
—
—
7,216
62,752
(2,438,964)
(2,376,212)
$
5,729,418 $
14,345 $
618,976 $
(5,784,526) $
578,213
See accompanying notes to the consolidated financial statements.
Baytex Energy Corp. 2020 Annual Report
51
Baytex Energy Corp.
Consolidated Statements of Cash Flows
(thousands of Canadian dollars)
Years Ended December 31
Notes
2020
2019
$
(2,438,964) $
(12,459)
12
17
5
5, 6
16
10
18
15
10
19
8
7
9
9
5
6
19
$
$
$
7,216
9,232
14,011
486,380
2,360,220
18,907
(2,128)
18,500
(901)
(160,967)
(7,168)
48,758
353,096
143,248
(5,925)
652,150
(833,672)
(44,199)
(4,490)
(275,850)
(2,280)
—
182
(32,031)
(314,469)
(5,572)
5,572
— $
102,358 $
1,155 $
15,894
(62,753)
11,764
731,686
187,822
18,448
—
82,817
(2,238)
(68,555)
(15,417)
(52,070)
834,939
(7,775)
(5,956)
—
(198,128)
(211,859)
(2,948)
(549,343)
(552)
(3,667)
1,487
(62,485)
(617,508)
5,572
—
5,572
112,241
1,160
CASH PROVIDED BY (USED IN):
Operating activities
Net loss
Adjustments for:
Share-based compensation
Unrealized foreign exchange loss (gain)
Exploration and evaluation
Depletion and depreciation
Impairments
Non-cash financing, accretion and early redemption expense
Non-cash other income
Unrealized financial derivatives loss
Gain on dispositions
Deferred income tax recovery
Asset retirement obligations settled
Change in non-cash working capital
Financing activities
Increase (decrease) in credit facilities
Payments on lease obligations
Net proceeds from issuance of long-term notes
Redemption of long-term notes
Investing activities
Additions to exploration and evaluation assets
Additions to oil and gas properties
Additions to other plant and equipment
Property acquisitions
Proceeds from dispositions
Change in non-cash working capital
Change in cash
Cash, beginning of year
Cash, end of year
Supplementary information
Interest paid
Income taxes paid
See accompanying notes to the consolidated financial statements.
52
Baytex Energy Corp. 2020 Annual Report
Baytex Energy Corp.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2020 and 2019
(all tabular amounts in thousands of Canadian dollars, except per common share amounts)
1. REPORTING ENTITY
Baytex Energy Corp. (the “Company” or “Baytex”) is an oil and gas corporation engaged in the acquisition, development and
production of oil and natural gas in the Western Canadian Sedimentary Basin and in Texas, United States. The Company’s
common shares are traded on the Toronto Stock Exchange under the symbol BTE. The Company’s head and principal office is
located at 2800, 520 – 3rd Avenue S.W., Calgary, Alberta, T2P 0R3, and its registered office is located at 2400, 525 – 8th Avenue
S.W., Calgary, Alberta, T2P 1G1.
2. BASIS OF PRESENTATION
The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards
("IFRS") as issued by the International Accounting Standards Board (the "IASB"). The significant accounting policies set forth
below were consistently applied to all periods presented.
The consolidated financial statements were approved by the Board of Directors of Baytex on February 24, 2021.
The consolidated financial statements have been prepared on a historical cost basis, with the exception of certain fair value
measurements noted in the accounting policies set forth below. The consolidated financial statements are presented in Canadian
dollars which is the functional currency of the Company. References to “US$” are to United States ("U.S.") dollars. All financial
information is rounded to the nearest thousand, except per share amounts or where otherwise indicated.
Current Environment and Estimation Uncertainty
Management makes judgements and assumptions about the future in deriving estimates used in preparation of these
consolidated financial statements in accordance with IFRS. Sources of estimation uncertainty include estimates used to
determine economically recoverable oil, natural gas, and natural gas liquids reserves, the recoverable amount of long-lived
assets or cash generating units, the provision for asset retirement obligations and the provision for income taxes and the related
deferred tax assets and liabilities.
In March 2020, the World Health Organization declared a global pandemic related to the novel coronavirus ("COVID-19"). The
emergence of COVID-19 and the steps taken by governments to control the spread of the virus resulted in significant instability in
the global economy and a sharp decline in demand for crude oil. This combined with the increased supply of crude oil due to the
Russia and Saudi Arabia (collectively, "OPEC+") price war resulted in an unprecedented collapse in global crude oil prices and
significant volatility during Q2/2020. Global crude oil prices began to recover during the second half of 2020 as Russia and
members of OPEC agreed to curtail production and governments began to ease restrictions which increased demand. In
Q4/2020 vaccines were approved and distribution began which fueled further optimism that demand will be restored. Vaccine
approval and distribution has continued in 2021 and OPEC+ has agreed to continue production curtailments which has resulted
in recent improvements in crude oil prices in 2021.
These factors have impacted our results for the year ended December 31, 2020. We recorded impairments of $2.4 billion for the
year ended December 31, 2020 which included amounts related to our exploration and evaluation assets (note 5) and oil and
gas properties (note 6). These impairments were a result of a sharp drop in forecasted prices for the commodities we produce. In
the current environment, assumptions and estimates regarding future commodity prices, the amount of economically recoverable
reserves, exchange rates, and interest rates are subject to greater variability than normal. Actual results may differ from these
estimates as the effect of future events cannot be determined with certainty.
We took action to protect our financial liquidity in response to the volatility in commodity prices and instability in the global
economy. We reduced our capital expenditures during 2020 and reduced production of oil and natural gas when commodity
prices did not support economic production. As a result of these actions we maintained $367.2 million of availability on our credit
facilities at December 31, 2020.
Measurement Uncertainty and Judgments
The preparation of the consolidated financial statements in accordance with IFRS requires management to make judgments,
estimates and assumptions that affect the application of accounting policies and reported amounts of assets, liabilities, revenues
and expenses. These judgments, estimates and assumptions are based on all relevant information available to the Company at
the time of financial statement preparation. Actual results can differ from those estimates as the effect of future events cannot be
determined with certainty. The key areas of judgment or estimation uncertainty that have a significant risk of causing material
adjustment to the reported amounts of assets, liabilities, revenues, and expenses are discussed below.
Baytex Energy Corp. 2020 Annual Report
53
Reserves
The Company uses estimates of oil, natural gas and natural gas liquids ("NGL") reserves in the calculation of depletion,
evaluating the recoverability of deferred income tax assets and in the determination of fair value estimates for non-financial
assets. The process to estimate reserves is complex and requires significant judgment. Estimates of the Company's reserves are
evaluated annually by independent reserves evaluators and represent the estimated recoverable quantities of oil, natural gas
and NGL and the related net cash flows. This evaluation of reserves is prepared in accordance with the reserves definition
contained in National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities" and the Canadian Oil and Gas
Evaluation Handbook.
Estimates of economically recoverable oil, natural gas and NGL and their future net cash flows are based on a number of factors
and assumptions. Changes to estimates and assumptions such as forward price forecasts, production rates, ultimate reserve
recovery, timing and amount of capital expenditures, production costs, marketability of oil and natural gas, royalty rates and other
geological, economic and technical factors could have a significant impact on reported reserves. Changes in the Company's
reserves estimates can have a significant impact on the carrying values of the Company's oil and gas properties, the calculation
of depletion, the valuation of deferred income tax assets, the timing of cash flows for asset retirement obligations, asset
impairments and estimates of fair value determined in accounting for business combinations.
Cash-generating Units ("CGUs")
The Company's oil and gas properties are aggregated into CGUs which are the smallest identifiable group of assets that
generates cash flows that are largely independent of the cash flows from other assets or groups of assets. The aggregation of
assets in CGUs requires management judgment and is based on geographical proximity, shared infrastructure and similar
exposure to market risk.
Identification of Impairment and Impairment Reversal Indicators
Judgment is required to assess when indicators of impairment or impairment reversal exist and when a calculation of the
recoverable amount is required. The CGUs comprising oil and gas properties are reviewed at each reporting date to assess
whether there is any indication of impairment or impairment reversal. The assessment for each CGU considers significant
changes in reservoir performance including forecasted production volumes, forecasted royalty, operating, capital and
abandonment and reclamation costs, forecasted oil and gas prices and the resulting cash flows from proved plus probable oil
and gas reserves.
Measurement of Recoverable Amount
If indicators of impairment or impairment reversal are determined to exist, the recoverable amount of an asset or CGU is
calculated based on the higher of value-in-use ("VIU") and fair value less cost of disposal ("FVLCD"). These calculations require
the use of estimates and assumptions including cash flows associated with proved plus probable oil and gas reserves, the
discount rate used to present value future cash flows and assumptions regarding the timing and amount of capital expenditures
and future abandonment and reclamation obligations. Any changes to these estimates and assumptions could impact the
calculation of the recoverable amount and the carrying value of assets.
Exploration and Evaluation ("E&E") Assets
Costs associated with acquiring oil and natural gas licenses and exploratory drilling are accumulated as E&E assets pending
determination of technical feasibility and commercial viability. The determination of technical feasibility and commercial viability of
E&E assets for the purposes of reclassifying such assets to oil and gas properties is subject to management judgment.
Management uses the establishment of commercial reserves as the basis for determining technical feasibility and commercial
viability. Upon determination of commercial reserves, E&E assets are tested for impairment and reclassified to oil and natural gas
properties.
Asset Retirement Obligations
The Company's provision for asset retirement obligations is based on estimated costs to abandon and reclaim the wells and the
facilities, the estimated time period during which these costs will be incurred in the future, and discount and inflation rates. The
provision for asset retirement obligations represents management's best estimate of the present value of the future
abandonment and reclamation costs required under current regulatory requirements. Actual abandonment and reclamation costs
could be materially different from estimated amounts.
Income Taxes
Tax regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to
change and there are differing interpretations requiring management judgment. Deferred tax assets are recognized when it is
considered probable that deductible temporary differences will be recovered in future periods, which requires management
54
Baytex Energy Corp. 2020 Annual Report
judgment. Deferred tax liabilities are recognized when it is considered probable that temporary differences will be payable to tax
authorities in future periods, which requires management judgment. Income tax filings are subject to audit and re-assessment
and changes in facts, circumstances and interpretations of the standards may result in a material change to the Company's
provision for income taxes. Estimates of future income taxes are subject to measurement uncertainty.
3. SIGNIFICANT ACCOUNTING POLICIES
Changes in Significant Accounting Policies
Business Combinations
Baytex adopted amendments to IFRS 3 Business Combinations effective January 1, 2020, which will be applied prospectively to
acquisitions that occur on or after January 1, 2020. These amendments did not result in changes to the Company's accounting
policies for applying the acquisition method but could result in future acquisitions being accounted for as an asset acquisition as
opposed to a business combination should the criteria of the optional asset concentration test within these amendments be met.
Significant Accounting Policies
Consolidation
The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. Subsidiaries are
entities controlled by the Company. Control exists when the Company has the power to govern the financial and operating
policies to obtain benefits from its activities. Significant subsidiaries included in the Company's accounts include Baytex Energy
USA, Inc., Baytex Energy Ltd. and Baytex Energy Limited Partnership. Intercompany transactions are eliminated in preparation
of the consolidated financial statements.
Many of the Company's exploration, development and production activities are conducted through joint arrangements. The
consolidated financial statements include the Company's proportionate share of the assets, liabilities, revenues and expenses
generated by joint arrangements.
Business Combinations
Business combinations are accounted for using the acquisition method of accounting when the acquired assets meet the
definition of a business under IFRS. The cost of an acquisition is measured as cash paid and the fair value of assets given,
equity instruments issued and liabilities incurred or assumed at the date of exchange. The acquired identifiable assets and
liabilities assumed are measured at their fair values at the date of acquisition. Any excess of the cost of acquisition over the fair
value of the net identifiable assets acquired is recognized as goodwill. If the cost of acquisition is below the fair values of the
identifiable net assets acquired, the difference is recognized as a bargain purchase gain in net income or loss. Associated
transaction costs are expensed when incurred.
Revenue Recognition
Revenue from the sale of light oil and condensate, heavy oil, natural gas liquids, and natural gas is recognized based on the
consideration specified in contracts with customers. Baytex recognizes revenue by unit of production and when control of the
product transfers to the customer and collection is reasonably assured. This is generally at the point in time when the customer
obtains legal title to the product which is when it is physically transferred to the pipeline or other transportation method agreed
upon.
The nature of the Company's performance obligations, including roles of third parties and partners, are evaluated to determine if
the Company acts as a principal. Baytex recognizes revenue on a gross basis when it acts as the principal and has primary
responsibility for the transaction. Revenue is recognized on a net basis when Baytex acts in the capacity of an agent rather than
as a principal.
The transaction price for variable price contracts in the Canadian and U.S. operating segments is based on a representative
commodity price index, and may include adjustments for quality, location, delivery method, or other factors depending on the
agreed upon terms of the contract. The amount of revenue recorded can vary depending on the grade, quality and quantities of
oil or natural gas transferred to customers. Market conditions, which impact the Company's ability to negotiate certain
components of the transaction price, can also cause the amount of revenue recorded to fluctuate from period to period.
Tariffs, tolls and fees charged to other entities for the use of pipelines and facilities owned by Baytex are evaluated by
management to determine if these originate from contracts with customers or from incidental or collaborative arrangements.
Tariffs, tolls and fees charged to other entities that are from contracts with customers are recognized in revenue when the related
services are provided.
Baytex Energy Corp. 2020 Annual Report
55
Exploration and Evaluation Assets
Pre-license costs, including certain geological, geophysical and seismic expenditures, are incurred before the legal rights to
explore a specific area have been obtained. These costs are charged to exploration expense in the period in which they are
incurred.
Once the legal right to explore has been acquired, costs directly associated with an exploration program are capitalized as an
intangible asset until results of the exploration program have been evaluated. Costs capitalized as E&E assets include costs of
license acquisition, technical services and studies, seismic acquisition, exploration drilling and testing of initial production results.
E&E costs are subject to technical, commercial and management review to confirm the continued intent to develop or otherwise
extract the underlying reserves. The technical feasibility and commercial viability of extracting petroleum and natural gas
resources is dependent on the existence of economically recoverable reserves for the project. If the asset is determined not to be
technically feasible or commercially viable the accumulated E&E costs associated with the exploration project are charged to
E&E expense in the period the determination is made.
Upon determination of technical feasibility and commercial viability, as evidenced by the classification of proved or probable
reserves and management's intention to develop the E&E asset, the accumulated costs associated with the exploration project
are tested for impairment and transferred to oil and gas properties.
Oil and Gas Properties
Items of oil and gas properties are initially recorded at cost. The initial cost of oil and gas properties includes the costs to acquire
developed or producing oil and gas properties, and to develop oil and gas properties, such as costs of completing geological and
geophysical surveys, drilling development wells, and the costs to construct and install development infrastructure such as
wellhead equipment and processing facilities.
Oil and gas properties includes costs related to planned major inspection, overhaul and turnaround activities to maintain items of
oil and gas properties and benefit future years of operations. Replacements outside of a major inspection, overhaul or turnaround
are recognized as oil and gas properties when it is probable the future economic benefits of the replacement will be realized by
the Company. The carrying amount of any replaced or disposed item of oil and gas properties is derecognized. Repair and
maintenance costs incurred for servicing an item of oil and gas properties is recorded as operating expense as incurred.
Depletion and Depreciation
The costs associated with an item of oil and gas properties are depleted on a unit-of-production basis by depletable area over
proved plus probable reserves once commercial production has commenced. Future development costs required to bring those
reserves into production are included in the depletable base. For purposes of the depletion calculation, petroleum and natural
gas reserves are converted to a common unit of measurement on the basis of their relative energy content where six thousand
cubic feet of natural gas equates to one barrel of oil equivalent.
The depreciation methods and estimated useful lives for other plant and equipment are as follows:
Classification
Motor Vehicles
Office Equipment
Method
Diminishing balance
Diminishing balance
Computer Hardware
Diminishing balance
Furniture and Fixtures
Diminishing balance
Leasehold Improvements
Straight-line over life of the lease
Lease assets
Other Assets
Straight-line over the shorter of the useful life or the lease term
Diminishing balance
Rate or period
15%
20%
30%
10%
Various
Various
Various
The expected lives of other plant and equipment are reviewed on an annual basis and, if necessary, changes in expected useful
lives are accounted for prospectively.
56
Baytex Energy Corp. 2020 Annual Report
Impairment and Impairment Reversals
Non-financial assets
The Company reviews its non-financial assets, other than E&E assets, for indicators of impairment and impairment reversal at
the end of each reporting period. The recoverable amount of the asset is estimated if indicators of impairment or impairment
reversal exist. E&E assets are assessed for impairment when they are reclassified to oil and gas properties and if facts and
circumstances suggest that the carrying amount exceeds the recoverable amount.
When reviewing for indicators of impairment and impairment reversal, and testing for impairment or impairment reversal when
indicators have been identified, assets are grouped together at a CGU level. The recoverable amount of an asset or CGU is the
higher of its FVLCD and its VIU. The determination of recoverable amount includes estimates of proved and probable oil and gas
reserves and the associated cash flows. Factors that impact these cash flows includes CGU production volumes, royalty
obligations, operating costs, capital costs, forecast commodity prices, along with inflation and discount rates used to estimate
present value. FVLCD is determined as the amount that would be obtained from the sale of an asset or CGU in an arm's length
transaction between willing parties. In determining FVLCD, recent market transactions are considered if available. In the absence
of such transactions, an appropriate valuation model is used. VIU is assessed using the present value of the estimated future
cash flows of the asset or CGU. The estimated future cash flows are adjusted for risks specific to the asset or CGU and are
discounted using a discount rate that reflects current market assessments of the time value of money.
Where the carrying amount of a CGU exceeds its recoverable amount, the CGU is considered impaired and is written down to its
recoverable amount. The impairment reduces the carrying amount of any goodwill allocated to the CGU first, with any remaining
impairment being allocated to the individual assets in the CGU on a pro-rata basis.
Impairments may be reversed for all CGUs and individual assets, other than goodwill, when there is indication that a previously
recognized impairment may no longer exist or may have decreased. If such indication exists, the recoverable amount is
estimated. An impairment may be reversed only to the extent that the asset’s revised carrying amount does not exceed the
carrying amount that would have been determined, net of depreciation and depletion, had no impairment been recognized.
Impairment recognized in relation to goodwill is not reversed for subsequent increases in its recoverable amount.
Impairments and impairment reversals are recorded in net income or loss in the period the impairment or impairment reversal
occurs.
Leases
A contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in
exchange for consideration. A lease obligation and corresponding right-of-use asset ("lease asset") are recognized at the
commencement of the lease. The present value of the lease obligation is based on the future lease payments and is discounted
using the Company's incremental borrowing rate when the rate implicit in the lease is not readily available. The Company uses a
single discount rate for a portfolio of leases with similar characteristics. The lease asset is recognized at the amount of the lease
obligation, adjusted for lease incentives received and initial direct costs, on commencement of the lease. Depreciation is
recognized on the lease asset over the shorter of the estimated useful life of the asset or the lease term.
Lease payments are allocated between the liability and interest expense. Interest expense is recognized on the lease obligations
using the effective interest rate method and payments are applied against the lease obligation.
Management judgement is required to determine the discount rate used to calculate the present value of the lease obligation.
The carrying amounts of the lease assets, lease obligations, and the resulting interest and depletion and depreciation expense
are based on the implicit interest rate within the lease arrangement or, if this information is unavailable, the incremental
borrowing rate. Incremental borrowing rates are based on judgments including economic environment, term, and the underlying
risk inherent to the asset.
Asset Retirement Obligations
The Company recognizes asset retirement obligations when it has a legal or constructive obligation as a result of past events, it
is probable that an outflow of economic resources will be required to settle the obligation and a reliable estimate can be made of
the amount of the obligation. The Company’s asset retirement obligations are based on its net ownership in wells and facilities.
Management estimates the costs to abandon and reclaim the wells and the facilities using existing technology and the estimated
time period during which these costs will be incurred in the future.
Baytex Energy Corp. 2020 Annual Report
57
Asset retirement obligations are recognized for future asset retirement costs associated with the abandonment and reclamation
of the Company's E&E assets and oil and gas properties. Asset retirement obligations are measured at the present value of
management's best estimate of the future cash flows required to settle the present obligation, discounted using the risk-free
interest rate. The present value of the liability is capitalized as part of the cost of the related asset and depleted over its useful
life. The asset retirement obligation is accreted until the date of expected settlement of the retirement obligation and is
recognized within finance expense in the statements of income or loss. Changes in the future cash flow estimates resulting from
revisions to the estimated timing or amount of undiscounted cash flows or the discount rates are recognized as changes in the
asset retirement obligation provision and related asset at each reporting date.
Foreign Currency Translation
Foreign transactions
Transactions completed in currencies other than the functional currency are translated into the functional currency at the
exchange rates prevailing at the time of the transactions. Foreign currency assets and liabilities are translated to functional
currency at the period-end exchange rate. Revenue and expenses are translated to functional currency using the average
exchange rate for the period. Realized and unrealized gains and losses resulting from the settlement or translation of foreign
currency transactions are included in net income or loss.
Foreign operations
The functional currency of the Company's subsidiaries is the currency of the primary economic environment in which the entity
operates. Certain subsidiaries of the Company operate and transact primarily in currencies other than the Canadian dollar. The
designation of a subsidiary's functional currency is a management judgment based on the currency of the primary economic
environment in which the subsidiary operates.
The financial statements of each entity are translated into Canadian dollars in preparation of the Company's consolidated
financial statements. The assets and liabilities of a foreign operation are translated to Canadian dollars at the period-end
exchange rate. Revenues and expenses of foreign operations are translated to Canadian dollars using the average exchange
rate for the period. Foreign exchange differences are recognized in other comprehensive income or loss.
If the Company or any of its entities disposes of its entire interest in a foreign operation, or loses control, joint control, or
significant influence over a foreign operation, the accumulated foreign currency translation gains or losses related to the foreign
operation are recognized in net income or loss.
Financial Instruments
Financial assets are initially classified into three categories: measured at amortized cost; fair value through other comprehensive
income (“FVOCI”); or fair value through profit or loss (“FVTPL”). Financial assets are categorized based on the Company’s
objective for the asset and the contractual cash flows. A financial asset is classified as amortized cost if the asset is held with the
objective to collect contractual cash flows that are solely payments of principal and interest on principal amounts outstanding. A
financial asset is classified as FVOCI if the asset is held with the objective to both collect contractual cash flows and sell the
financial asset. All other financial assets are measured at FVTPL. Financial assets are assessed for impairment using an
expected credit loss model. Trade and other receivables are classified and measured at amortized cost.
The measurement categories for each class of financial asset and financial liability is set forth in the following table.
Financial Instrument
Cash and cash equivalents
Trade and other receivables
Financial derivatives
Trade and other payables
Credit facilities
Long-term notes
Lease obligations
Classification
Amortized cost
Amortized cost
Fair value through profit or loss
Amortized cost
Amortized cost
Amortized cost
Amortized cost
An embedded derivative is a component of a contract that modifies the cash flows of the contract. These hybrid contracts consist
of a host contract and an embedded derivative. The embedded derivative is separated from the host contract and accounted for
as a derivative unless the economic characteristics and risks of the embedded derivative are closely related to the host contract.
The embedded derivatives are measured at FVTPL.
58
Baytex Energy Corp. 2020 Annual Report
Debt issuance costs related to the amendment of our credit facilities or the issuance of long term notes are capitalized and
amortized as financing costs over the term of the credit facilities or long term notes. For a financial asset or a financial liability
carried at amortized cost, transaction costs directly attributable to acquiring or issuing the asset or liability are added to, or
deducted from, the fair value on initial recognition and amortized through net income or loss over the term of the financial
instrument. Transaction costs that are directly attributable to the acquisition or issue of a financial asset or a financial liability
classified as FVTPL are expensed at inception of the contract.
The Company formally documents its risk management objectives and strategies to manage exposures to fluctuations in
commodity prices, interest rates and foreign currency exchange rates. The risk management policy permits the use of certain
derivative financial instruments, including swaps and collars, to manage these fluctuations. All transactions of this nature entered
into by the Company are related to underlying financial instruments or future petroleum and natural gas production. These
instruments are classified as FVTPL. The Company does not use financial derivatives for trading or speculative purposes. The
Company has not designated its financial derivative contracts as effective accounting hedges, and therefore has not applied
hedge accounting. As a result, the Company applies the fair value method of accounting for all derivative instruments by
recording an asset or liability on the statements of financial position and recognizing changes in the fair value of the instrument in
the statements of income or loss for the current period. The fair values of these instruments are based on quoted market prices
or, in their absence, third-party market indications and forecasts. Attributable transaction costs are recognized in net income or
loss when incurred.
The Company has accounted for its physical delivery sales contracts, which were entered into and continue to be held for the
purpose of receipt or delivery of non-financial items in accordance with its expected purchase, sale or usage requirements as
executory contracts. As such, these contracts are not considered to be derivative financial instruments and have not been
recorded at fair value on the statements of financial position. Settlements on these physical delivery sales contracts are
recognized in revenue in the period the product is delivered to the sales point.
Impairment of financial assets is determined by calculating the expected credit loss ("ECL"). The Company measures an ECL
allowance for trade and other receivables. The Company determines the ECL which is the probability of default events related to
the financial asset by using historical realized bad debts and forward looking information. The carrying amounts of financial
assets are reduced by the amount of the ECL through an allowance account and losses are recognized in the statement of
income or loss.
Fair Value of Financial Instruments
Baytex classifies the fair value of financial instruments according to the following hierarchy based on the amount of observable
inputs used to value the instruments:
•
•
•
Level 1: Values based on unadjusted quoted prices in active markets that are accessible at the measurement date for
identical assets or liabilities.
Level 2: Values based on quoted prices in markets that are not active or model inputs that are observable either directly
or indirectly for substantially the full term of the asset or liability.
Level 3: Values based on prices or valuation techniques that require inputs that are both unobservable and significant to
the overall fair value measurement.
Income Taxes
Current and deferred income taxes are recognized in net income or loss, except when they relate to items that are recognized
directly in equity, in which case the current and deferred taxes are also recognized directly in equity.
Current income taxes for the current and prior periods are measured at the amount expected to be recoverable from or payable
to the taxation authorities based on the income tax rates enacted at the end of the reporting period. The Company recognizes
the financial statement impact of a tax filing position when it is probable that the position will be sustained upon audit. The liability
is measured based on an assessment of possible outcomes and their associated probabilities.
The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred income taxes
are recorded for the effect of any temporary differences between the carrying amounts of assets and liabilities in the consolidated
financial statements and the corresponding tax basis used in the computation of taxable income. Deferred income tax liabilities
are generally recognized for all taxable temporary differences. Deferred income tax assets are recognized for all temporary
differences deductible to the extent future recovery is probable. The carrying amount of deferred income tax assets is reviewed
at the end of each reporting period and reduced to the extent that it is no longer probable that sufficient taxable income will be
available to allow all or part of the asset to be recovered. Deferred income taxes are calculated using enacted or substantively
enacted tax rates. Deferred income tax balances are adjusted for any changes in the enacted or substantively enacted tax rates
and the adjustment is recognized in the period that the rate change occurs.
Baytex Energy Corp. 2020 Annual Report
59
Share-based Compensation Plans
The Company has a full-value award plan (the "Share Award Incentive Plan") pursuant to which restricted awards and
performance awards (collectively, "share awards") may be granted to the directors, officers and employees of the Company and
its subsidiaries. The maximum number of common shares issuable under the Share Award Incentive Plan (and any other long-
term incentive plans of the Company) shall not at any time exceed 3.8% of the then-issued and outstanding common shares.
Each restricted award entitles the holder to be issued the number of common shares designated in the restricted award (plus
dividend equivalents). Each performance award entitles the holder to be issued the number of common shares designated in the
performance award (plus dividend equivalents) multiplied by a payout multiplier. Expenses related to the Share Award Incentive
Plan are determined based on the fair value of the share awards on the grant date which is based on quoted market prices for
the Company's common shares. Both restricted and performance awards are expensed over the vesting period using the graded
vesting method, with a corresponding increase to contributed surplus. The payout multiplier is dependent on the performance of
the Company relative to predefined corporate performance measures for a particular period. In the case of both restricted and
performance awards, the number of common shares to be issued on the applicable issue date is adjusted to account for the
payments of dividends from the grant date to the applicable issue date.
The Company has a cash-settled incentive award plan (the "Incentive Award Plan") pursuant to which incentive awards may be
granted to officers and employees of the Company and its subsidiaries. Each incentive award entitles the holder to receive a
cash payment equal to the value of one Baytex common share at the time of vesting. The incentive awards vest in equal
tranches on the first, second and third anniversaries of the grant date. The cumulative expense is recognized at fair value at
each period end and is included in trade and other payables.
.
60
Baytex Energy Corp. 2020 Annual Report
4. SEGMENTED FINANCIAL INFORMATION
Baytex's reportable segments are determined based on the geographic location and nature of the underlying operations:
•
•
•
Canada includes the exploration for, and the development and production of, crude oil and natural gas in Western
Canada;
U.S. includes the exploration for, and the development and production of, crude oil and natural gas in the U.S.; and
Corporate includes corporate activities and items not allocated between operating segments.
Years Ended December 31
2020
2019
2020
2019
2020
2019
2020
2019
Canada
U.S.
Corporate
Consolidated
Revenue, net of royalties
Petroleum and natural gas sales
$ 571,741 $ 1,077,724 $ 403,736 $ 728,195 $
— $
— $ 975,477 $ 1,805,919
Royalties
Expenses
Operating
Transportation
Blending and other
General and administrative
Exploration and evaluation
Depletion and depreciation
Impairment
Share-based compensation
Financing and interest
Financial derivatives (gain) loss
Foreign exchange loss (gain)
Gain on dispositions
Other income
(46,064)
(107,467)
(117,671)
(212,774)
525,677
970,257
286,065
515,421
247,050
298,303
84,295
99,413
28,437
48,381
—
43,942
68,795
—
14,011
11,764
—
—
—
—
—
—
—
—
309,420
463,501
169,439
261,766
1,737,000
187,822
623,220
—
—
—
—
—
—
—
—
(901)
(2,238)
(2,128)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
34,268
45,469
—
—
7,521
—
(163,735)
(320,241)
811,742
1,485,678
331,345
397,716
28,437
48,381
34,268
14,011
43,942
68,795
45,469
11,764
6,419
486,380
731,686
— 2,360,220
187,822
9,469
15,894
9,469
15,894
125,441
125,865
125,441
125,865
(29,336)
7,197
(29,336)
7,197
8,688
(61,787)
8,688
(61,787)
—
—
(901)
(3,176)
(7,526)
(5,304)
(2,238)
(7,526)
2,381,270
1,071,889
876,954
361,179
152,875
131,531
3,411,099
1,564,599
Net income (loss) before income taxes
(1,855,593)
(101,632)
(590,889)
154,242
(152,875)
(131,531) (2,599,357)
(78,921)
Income tax expense (recovery)
Current income tax expense
469
101
105
Deferred income tax (recovery) expense
(77,201)
(32,942)
(57,199)
(76,732)
(32,841)
(57,094)
1,992
10,055
12,047
—
—
574
2,093
(26,567)
(45,668)
(160,967)
(68,555)
(26,567)
(45,668)
(160,393)
(66,462)
Net income (loss)
$ (1,778,861) $
(68,791) $ (533,795) $ 142,195 $ (126,308) $
(85,863) $ (2,438,964) $
(12,459)
Total oil and natural gas capital
expenditures (1)
$ 174,770 $ 376,543 $ 105,388 $ 177,928 $
— $
— $ 280,158 $ 554,471
(1)
Includes acquisitions, net of proceeds from divestitures.
As at
Canadian assets
U.S. assets
Corporate assets
Total consolidated assets
December 31, 2020
December 31, 2019
$
$
1,646,412 $
1,737,533
24,151
3,408,096 $
3,484,123
2,403,310
26,650
5,914,083
Baytex Energy Corp. 2020 Annual Report
61
5. EXPLORATION AND EVALUATION ASSETS
Balance, beginning of year
$
Capital expenditures
Property acquisitions
Divestitures
Impairment
Property swaps
Exploration and evaluation expense
Transfers to oil and gas properties (note 6)
Foreign currency translation
Balance, end of year
December 31, 2020
December 31, 2019
320,210 $
4,490
—
—
(113,058)
468
(14,011)
(8,585)
2,351
$
191,865 $
358,935
2,948
1,523
(443)
(7,822)
417
(11,764)
(16,204)
(7,380)
320,210
At March 31, 2020, the Company identified indicators of impairment for the exploration and evaluation assets within each of its
six CGUs. The estimated recoverable amount was below the carrying value of the exploration and evaluation assets in the
Conventional, Peace River, Lloydminster, Viking and Eagle Ford CGUs and an impairment of $127.9 million was recorded as at
March 31, 2020. The recoverable amount of each CGU was based on its FVLCD and was estimated with reference to arm's
length transaction in comparable locations and the discounted cash flows associated with the Company's future development
plans. The following table indicates the impairment booked for each CGU at March 31, 2020.
Conventional CGU
Peace River CGU
Lloydminster CGU
Viking CGU
Eagle Ford CGU
Impairment at
March 31, 2020
4,000
20,000
42,000
13,000
48,861
127,861
$
$
At December 31, 2020, the Company estimated the recoverable amount of the exploration and evaluation assets within each of
its six CGUs due to the ongoing volatility in future oil and natural gas prices. The recoverable amount supported the carrying
amount for the Conventional, Peace River, Lloydminster, and Duvernay CGUs and no impairment or impairment reversal was
recorded. The recoverable amount for the Viking and Eagle Ford CGUs exceeded their carrying amounts which resulted in an
impairment reversal of $14.8 million at December 31, 2020. The recoverable amount of each CGU was based on its FVLCD and
was estimated with reference to arm's length transaction in comparable locations and the discounted cash flows associated with
the Company's future development plans. The following table indicates the impairment reversal booked for the Viking and Eagle
Ford CGUs at December 31, 2020.
Viking CGU
Eagle Ford CGU
Impairment reversal at
December 31, 2020
$
$
2,000
12,803
14,803
At December 31, 2019 the Company identified indicators of impairment for the exploration and evaluation assets within the
Peace River CGU. The estimated recoverable amount was below the carrying value of the exploration and evaluation assets in
the Peace River CGU and an impairment $7.8 million was recorded as at December 31, 2019. There were no indicators of
impairment for exploration and evaluation assets in the remaining CGUs at December 31, 2019.
62
Baytex Energy Corp. 2020 Annual Report
6. OIL AND GAS PROPERTIES
Balance, December 31, 2018
Capital expenditures
Property acquisitions
Transfers from exploration and evaluation assets (note 5)
Change in asset retirement obligations (note 10)
Divestitures
Property swaps
Impairment
Foreign currency translation
Depletion
Balance, December 31, 2019
Capital expenditures
Transfers from exploration and evaluation assets (note 5)
Change in asset retirement obligations (note 10)
Property swaps
Impairments
Foreign currency translation
Depletion
Balance, December 31, 2020
Accumulated
Cost
depletion Net book value
$
10,744,533 $
(4,926,644) $
5,817,889
549,343
2,636
16,204
23,894
(2,069)
1,773
—
(208,017)
—
—
—
—
—
1,690
—
(180,000)
89,813
(725,267)
549,343
2,636
16,204
23,894
(379)
1,773
(180,000)
(118,204)
(725,267)
$
11,128,297 $
(5,740,408) $
5,387,889
275,850
8,585
94,994
(1,190)
—
—
—
178
275,850
8,585
94,994
(1,012)
—
(2,247,162)
(2,247,162)
(82,860)
—
120,123
(478,859)
37,263
(478,859)
$
11,423,676 $
(8,346,128) $
3,077,548
Baytex recorded total impairments related to oil and gas properties of $2.2 billion for the year ended December 31, 2020 and
$180.0 million for the year ended December 31, 2019.
At March 31, 2020, the Company identified indicators of impairment for each of its six CGUs due to a significant decline in
forecasted commodity prices. The recoverable amount was not sufficient to support the carrying amount which resulted in an
impairment of $2.6 billion recorded at March 31, 2020. The recoverable amount of each CGU was based on its FVLCD which
was estimated using a discounted cash flow model of proved plus probable cash flows from an independent reserve report
prepared as at December 31, 2019 and was adjusted for operations between December 31, 2019 and March 31, 2020. The
after-tax discount rates applied to the cash flows were between 8% and 14%.
The recoverable amount of the Company's CGUs were calculated at March 31, 2020 using the following benchmark reference
prices for the years 2020 to 2029 adjusted for commodity differentials specific to the Company. The prices and costs subsequent
to 2029 have been adjusted for inflation at an annual rate of 2%.
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
WTI crude oil (US$/bbl)
29.17
40.45
49.17
53.28
55.66
56.87
58.01
59.17
60.35
61.56
WCS heavy oil (CA$/bbl)
19.21
34.65
46.34
51.25
54.28
55.72
56.96
58.22
59.51
60.82
LLS crude oil (US$/bbl)
32.17
43.80
52.55
56.68
59.10
60.35
61.52
62.72
63.94
65.19
Edmonton par oil (CA$/bbl)
29.22
46.85
59.27
65.02
68.43
69.81
71.24
72.70
74.19
75.71
Henry Hub gas (US$/mmbtu)
AECO gas (CA$/mmbtu)
Exchange rate (CAD/USD)
2.10
1.74
1.41
2.58
2.20
1.37
2.79
2.38
1.34
2.86
2.45
1.34
2.93
2.53
1.34
3.00
2.60
1.33
3.07
2.66
1.33
3.13
2.72
1.33
3.19
2.79
1.33
3.25
2.85
1.33
Baytex Energy Corp. 2020 Annual Report
63
The following table demonstrates the sensitivity of the estimated recoverable amount of the Company's CGUs to reasonably
possible changes in key assumptions inherent in the estimate.
Recoverable
amount
Impairment
Change in discount
rate of 1%
Change in oil price
of $2.50/bbl
Change in gas
price of $0.25/mcf
Conventional CGU
$
37,444 $
41,000 $
3,000 $
3,500 $
Peace River CGU
Lloydminster CGU
Duvernay CGU
Viking CGU
Eagle Ford CGU
109,631
227,967
61,197
962,134
1,576,423
345,000
470,000
5,000
915,000
812,488
9,500
25,000
5,500
57,000
120,750
53,500
69,500
9,500
123,000
141,500
$
2,974,796 $
2,588,488 $
220,750 $
400,500 $
8,500
3,000
—
1,500
4,000
32,000
49,000
At December 31, 2020, the Company estimated the recoverable amount of each of its six CGUs due to the volatility in
commodity prices during the year and a reduction in future development costs per well for the Viking and Eagle Ford CGUs. The
recoverable amount supported the carrying amount for the Conventional, Peace River, Lloydminster, and Duvernay CGUs and
no impairment or impairment reversal was recorded. The recoverable amount for the Viking and Eagle Ford CGUs exceeded
their carrying amounts which resulted in an impairment reversal of $341.3 million recorded at December 31, 2020. The
recoverable amount for each CGU was based on its FVLCD which was estimated using a discounted cash flow model of proved
plus probable cash flows from an independent reserve report prepared as at December 31, 2020. The after-tax discount rates
applied to the cash flows were between 10% and 17%.
The recoverable amount of the Company's CGUs were calculated at December 31, 2020 using the following benchmark
reference prices for the years 2021 to 2030 adjusted for commodity differentials specific to the Company. The prices and costs
subsequent to 2030 have been adjusted for inflation at an annual rate of 2%.
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
WTI crude oil (US$/bbl)
47.17
50.17
53.17
54.97
56.07
57.19
58.34
59.50
60.69
61.91
WCS heavy oil (CA$/bbl)
44.63
48.18
52.10
54.10
55.19
56.29
57.42
58.57
59.74
60.93
LLS crude oil (US$/bbl)
49.50
52.85
55.87
57.69
58.82
59.97
61.15
62.34
63.56
64.83
Edmonton par oil (CA$/bbl)
55.76
59.89
63.48
65.76
67.13
68.53
69.95
71.40
72.88
74.34
Henry Hub gas (US$/mmbtu)
AECO gas (CA$/mmbtu)
Exchange rate (CAD/USD)
2.83
2.78
1.30
2.87
2.70
1.31
2.90
2.61
1.31
2.96
2.65
1.31
3.02
2.70
1.31
3.08
2.76
1.31
3.14
2.81
1.31
3.20
2.87
1.31
3.26
2.92
1.31
3.33
2.98
1.31
The following table demonstrates the sensitivity of the estimated recoverable amount of the Company's CGUs to reasonably
possible changes in key assumptions inherent in the estimate.
Recoverable
amount
Impairment
reversal
Change in discount
rate of 1%
Change in oil price
of $2.50/bbl
Change in gas
price of $0.25/mcf
Conventional CGU
$
54,265 $
— $
1,000 $
3,000 $
Peace River CGU
Lloydminster CGU
Duvernay CGU
Viking CGU
Eagle Ford CGU
104,225
212,979
70,491
1,026,026
1,609,562
—
—
—
116,000
225,326
1,000
7,000
5,500
34,500
91,600
49,500
57,500
12,000
106,500
157,500
$
3,077,548 $
341,326 $
140,600 $
386,000 $
9,000
3,000
500
1,500
5,000
38,400
57,400
At December 31, 2019, the Company identified indicators of impairment for its Peace River CGU due to a sustained decline in
Canadian heavy oil prices and a reduction in planned exploration and development expenditures related to thermal properties in
the Peace River CGU. The recoverable amount of the Peace River CGU was based on its VIU which was estimated using a
discounted cash flow model using proved plus probable cash flows from an independent reserve report prepared as at
December 31, 2019 and an after-tax discount rate of 11%. The recoverable amount was not sufficient to support the carrying
amount of the CGU which resulted in an impairment of $180.0 million recorded as at December 31, 2019. There were no
indicators of impairment or impairment reversal for the remaining CGUs at December 31, 2019.
64
Baytex Energy Corp. 2020 Annual Report
7. LEASES
Lease Assets
Baytex had the following right-of-use assets at December 31, 2020.
Balance, January 1, 2019 (1)
Additions
Modifications
Depreciation
Balance, December 31, 2019
$
Additions
Modifications
Depreciation
Office Leases
$
14,775 $
Field
Equipment
Vehicles and
Other
2,254 $
1,668
4
(837)
969 $
159
19
(482)
3,089 $
665 $
962
80
(1,381)
2,750 $
203
7
(459)
416 $
Total
17,998
1,827
17
(6,223)
13,619
1,185
1,933
(5,639)
11,098
—
(6)
(4,904)
9,865 $
20
1,846
(3,799)
Balance, December 31, 2020
$
7,932 $
(1) The Company adopted IFRS 16 Leases on January 1, 2019 using the modified retrospective approach.
Lease Obligations
Baytex had the following future commitments associated with its lease obligations at December 31, 2020.
Less than 1 year
1 - 3 years
3 - 5 years
After 5 years
Total lease payments
Amounts representing interest over the term of the lease
Present value of net lease payments
Less current portion of lease obligations
Non-current portion of lease obligations
December 31, 2020
December 31, 2019
$
$
$
$
4,504 $
4,302
3,044
—
11,850 $
(774)
11,076 $
4,289
6,787 $
6,216
7,748
604
—
14,568
(685)
13,883
5,798
8,085
The Company recorded interest expense related to its lease obligations of $0.4 million and recorded lease payments of
$5.9 million for the year ended December 31, 2020 (December 31, 2019 - $0.6 million and 6.0 million, respectively).
8. CREDIT FACILITIES
Credit facilities - U.S. dollar denominated (1)
Credit facilities - Canadian dollar denominated
Credit facilities - principal (2)
Unamortized debt issuance costs
Credit facilities
December 31, 2020
December 31, 2019
$
$
$
140,815 $
510,358
651,173 $
(1,952)
649,221 $
206,144
300,327
506,471
(1,059)
505,412
(1) U.S. dollar denominated credit facilities balance was US$110.4 million as at December 31, 2020 (December 31, 2019 - US$159.0 million).
(2) The increase in the principal amount of the credit facilities outstanding from December 31, 2019 to December 31, 2020 is the result of net
draws of $145.0 million and a decrease in the reported amount of U.S. denominated debt of $0.3 million due to foreign exchange.
Baytex has US$575 million of revolving credit facilities (the "Revolving Facilities") and a $300 million non-revolving secured term
loan (the "Term Loan") (collectively the "Credit Facilities"). On March 3, 2020, Baytex amended its Credit Facilities to extend
maturity from April 2, 2021 to April 2, 2024. These facilities will automatically be extended to June 4, 2024 providing Baytex has
either refinanced, or has the ability to repay, the outstanding 2024 long-term notes with existing credit capacity as of April 1,
2024.
Baytex Energy Corp. 2020 Annual Report
65
The extendible secured Revolving Facilities are comprised of a US$50 million operating loan and a US$325 million syndicated
revolving loan for Baytex and a US$200 million syndicated revolving loan for Baytex's wholly-owned subsidiary, Baytex Energy
USA, Inc. The $300 million Term Loan is secured by the assets of Baytex's wholly-owned subsidiary, Baytex Energy Limited
Partnership.
The Credit Facilities are not borrowing base facilities and do not require annual or semi-annual reviews. The Credit Facilities
contain standard commercial covenants in addition to the financial covenants detailed below. There are no mandatory principal
payments required prior to maturity which could be extended upon Baytex's request. Advances (including letters of credit) under
the Credit Facilities can be drawn in either Canadian or U.S. funds and bear interest at the bank’s prime lending rate, bankers’
acceptance discount rates or London Interbank Offered Rates ("LIBOR"), plus applicable margins.
The LIBOR benchmark will no longer be published after December 31, 2021. We expect the LIBOR benchmark to be replaced
with an alternative that will apply to our U.S. dollar borrowing at our option. We do not expect this change to have a material
impact to Baytex as U.S. dollar borrowings under the credit facilities can also bear interest at the U.S. base loan rate.
At December 31, 2020, Baytex had $15.0 million of outstanding letters of credit (December 31, 2019 - $15.2 million) under the
Credit Facilities.
At December 31, 2020, Baytex was in compliance with all of the covenants contained in the Credit Facilities and is forecasting
compliance with these covenants based on current forward prices. The following table summarizes the financial covenants
applicable to the Revolving Facilities and Baytex's compliance therewith as at December 31, 2020.
Covenant Description
Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio)
Interest Coverage (3) (Minimum Ratio)
Position as at
December 31, 2020
1.6:1.0
3.9:1.0
Covenant
3.5:1.0
2.0:1.0
(1)
(2)
(3)
"Senior Secured Debt" is defined as the principal amount of the credit facilities and other secured obligations identified in the credit
agreement. As at December 31, 2020, the Company's Senior Secured Debt totaled $666.2 million which includes $651.2 million of principal
amounts outstanding and $15.0 million of letters of credit.
"Bank EBITDA" is calculated based on terms and definitions set out in the credit agreement which adjusts net income or loss for financing
and interest expenses, income tax, non-recurring losses, certain specific unrealized and non-cash transactions (including depletion,
depreciation, exploration and evaluation expenses, impairment, deferred income tax expense or recovery, unrealized gains and losses on
financial derivatives and foreign exchange and share-based compensation) and is calculated based on a trailing twelve month basis
including the impact of material acquisitions as if they had occurred at the beginning of the twelve month period. Bank EBITDA for the
twelve months ended December 31, 2020 was $414.9 million.
"Interest coverage" is computed as the ratio of Bank EBITDA to financing and interest expense, excluding accretion of debt issue costs and
asset retirement obligations, and is calculated on a trailing twelve month basis. Financing and interest expenses, excluding accretion of debt
issue costs and asset retirement obligations, for the twelve months ended December 31, 2020 were $106.1 million.
9. LONG-TERM NOTES
5.125% notes (US$400,000 – principal) due June 1, 2021
6.625% notes ($300,000 – principal) due July 19, 2022
5.625% notes (US$400,000 – principal) due June 1, 2024
8.75% notes (US$500,000 – principal) due April 1, 2027
Total long-term notes - principal (1)
Unamortized debt issuance costs
Total long-term notes - net of unamortized debt issuance costs
December 31, 2020
December 31, 2019
$
$
$
— $
—
510,200
637,750
1,147,950 $
(15,082)
1,132,868 $
518,600
300,000
518,600
—
1,337,200
(9,025)
1,328,175
(1) The decrease in the principal amount of long-term notes outstanding from December 31, 2019 to December 31, 2020 is the result of
principal repayments of $830.4 million, the issuance of $664.7 million aggregate principal amount and changes in the reported amount of
U.S. denominated debt of $23.6 million.
On February 5, 2020, Baytex issued US$500 million aggregate principal amount of senior unsecured notes due April 1, 2027
bearing interest at a rate of 8.75% per annum payable semi-annually (the "8.75% Senior Notes"). The 8.75% Senior Notes are
redeemable at Baytex's option, in whole or in part, at specified redemption prices after April 1, 2023 and will be redeemable at
par from April 1, 2026 to maturity. Transaction costs of $12.5 million were incurred in conjunction with the issuance which
resulted in net proceeds of $652.2 million.
On February 20, 2020, Baytex used a portion of the net proceeds from the issuance of the 8.75% Senior Notes to complete the
early redemption of the US$400 million principal amount of the 5.125% senior unsecured notes due June 1, 2021 at par plus
accrued interest. The principal payment was $530.4 million.
66
Baytex Energy Corp. 2020 Annual Report
On March 5, 2020, Baytex completed the early redemption of the $300 million principal amount of the 6.625% senior unsecured
notes due July 19, 2022 at 101.104% of the principal amount plus accrued interest. The principal payment was $300.0 million
plus early redemption expense of $3.3 million.
The long-term notes do not contain any significant financial maintenance covenants but do contain a debt incurrence covenant
that restricts the Company's ability to raise additional debt beyond the existing Credit Facilities and long-term notes.
10. ASSET RETIREMENT OBLIGATIONS
Balance, beginning of year
Liabilities incurred
Liabilities settled
Liabilities acquired from property acquisitions
Liabilities divested
Property swaps
Accretion (note 16)
Government grants (1)
Change in estimate (2)
Changes in discount rates and inflation rates
Foreign currency translation
Balance, end of year
Less current portion of asset retirement obligations
Non-current portion of asset retirement obligations
December 31, 2020
December 31, 2019
$
667,974 $
15,189
(7,168)
—
(721)
(525)
8,978
(2,128)
(12,771)
92,576
(1,021)
760,383 $
11,820
748,563 $
$
$
646,898
21,748
(15,417)
1,648
(1,331)
792
13,713
—
19,632
(17,486)
(2,223)
667,974
11,579
656,395
(1) Baytex received $2.1 million of government grants from the Governments of Alberta and Saskatchewan. The grants were used to abandon
and reclaim well sites which reduced our assets retirement obligations and was included in other income.
(2) Changes in the estimated costs, the timing of abandonment and reclamation and the status of wells are factors resulting in a change in
estimate.
At December 31, 2020, the undiscounted amount of estimated cash flows required to settle the asset retirement obligations is
$721.0 million (December 31, 2019 - $714.8 million). The discounted amount of estimated cash flow required to settle the asset
retirement obligations at December 31, 2020, calculated using an estimated inflation rate of 1.5% (December 31, 2019 - 1.4%)
and a risk free discount rate of 1.2% (December 31, 2019 - 1.8%), is $760.4 million (December 31, 2019 - $668.0 million). These
costs are expected to be incurred over the next 60 years.
11. SHAREHOLDERS' CAPITAL
The authorized capital of Baytex consists of an unlimited number of common shares without nominal or par value and
10.0 million preferred shares without nominal or par value, issuable in series. Baytex establishes the rights and terms of the
preferred shares upon issuance. As at December 31, 2020, no preferred shares have been issued by the Company and all
common shares issued were fully paid.
The holders of common shares may receive dividends as declared from time to time and are entitled to one vote per share at any
meetings of the holders of common shares. All common shares rank equally with regard to the Company's net assets in the
event the Company is wound-up or terminated.
Balance, December 31, 2018
Vesting of share awards
Balance, December 31, 2019
Vesting of share awards
Balance, December 31, 2020
Number of
Common Shares
(000s)
554,060 $
4,245
558,305 $
2,922
561,227 $
Amount
5,701,516
17,319
5,718,835
10,583
5,729,418
Baytex Energy Corp. 2020 Annual Report
67
12. SHARE-BASED COMPENSATION PLAN
The Company recorded compensation expense related to the share awards of $9.5 million for the year ended December 31,
2020 ($15.9 million for the year ended December 31, 2019) which includes $2.3 million of cash compensation expense related to
the incentive award plan and the associated equity total return swaps.
Share Award Plans
Baytex has a share award plan pursuant to which it issues restricted and performance awards. A restricted award entitles the
holder of each award to receive one common share of Baytex at the time of vesting. A performance award entitles the holder of
each award to receive between zero and two common shares on vesting; the number of common shares issued is determined by
a multiplier. The multiplier, which ranges between zero and two, is calculated based on a number of factors determined and
approved by the Board of Directors on an annual basis. The restricted awards and performance awards vest in equal tranches
on the first, second and third anniversaries of the grant date.
The weighted average fair value of share awards granted during the year ended December 31, 2020 was $1.48 per restricted
and performance award (December 31, 2019 - $2.63).
The number of share awards outstanding is detailed below:
(000s)
Balance, December 31, 2018
Granted
Vested and converted to common shares
Forfeited
Balance, December 31, 2019
Granted
Vested and converted to common shares
Forfeited
Balance, December 31, 2020
Number of
restricted
awards
Number of
performance
awards(1)
Total number of
share awards
3,243
3,184
(2,081)
(545)
3,801
2,239
(1,730)
(188)
4,122
3,273
3,245
(2,164)
(1,219)
3,135
3,253
(1,192)
(1,108)
4,088
6,516
6,429
(4,245)
(1,764)
6,936
5,492
(2,922)
(1,296)
8,210
(1) Based on underlying awards before applying the payout multiplier which can range from 0x to 2x.
Incentive Award Plan
Baytex has a cash-settled incentive award plan (the "Incentive Award" plan) whereby the holder of each incentive award is
entitled to receive a cash payment equal to the value of one Baytex common share at the time of vesting. The incentive awards
vest in equal tranches on the first, second and third anniversaries of the grant date. The cumulative expense is recognized at fair
value at each period end and is included in trade and other payables.
The Company uses equity total return swaps ("Equity TRS") on the equivalent number of Baytex common shares in order to fix
the aggregate cost of the Incentive Award plan at the fair value determined on the grant date. The carrying value of the financial
derivatives includes the fair value of the Equity TRS which was a liability of $1.1 million on December 31, 2020.
During the year ended December 31, 2020, Baytex granted 2.9 million awards under the Incentive Award plan at a fair value of
$1.50 per award.
Share Options
Baytex assumed share option plans pursuant to a business combination in 2018. No new grants will be made under the option
plans. At December 31, 2020, 0.3 million share options were outstanding with a weighted average remaining life of 0.3 years and
a weighted average exercise price of $5.40 (December 31, 2019 - 2.5 million options with a weighted average exercise price of
$6.83).
13. NET INCOME (LOSS) PER SHARE
Baytex calculates basic income or loss per share based on the net income or loss attributable to shareholders using the
weighted average number of shares outstanding during the period. Diluted income per share amounts reflect the potential
dilution that could occur if share awards and share options were converted to common shares. The treasury stock method is
used to determine the dilutive effect of share awards and share options whereby the potential conversion of share awards and
share options and the amount of compensation expense, if any, attributed to future services are assumed to be used to purchase
common shares at the average market price during the year.
68
Baytex Energy Corp. 2020 Annual Report
Years Ended December 31
2020
Weighted
average
common
shares
(000's)
Net loss
Net loss per
share
Net loss
2019
Weighted
average
common
shares
(000's)
Net loss per
share
Net loss - basic
$ (2,438,964)
560,657 $
(4.35) $
(12,459)
557,048 $
(0.02)
Dilutive effect of share awards
Dilutive effect of share options
—
—
—
—
—
—
—
—
—
—
—
—
Net loss - diluted
$ (2,438,964)
560,657 $
(4.35) $
(12,459)
557,048 $
(0.02)
For the years ended December 31, 2020 and December 31, 2019, all share awards and share options were excluded from the
calculation of diluted earnings per share as their effect was anti-dilutive given the Company recorded a net loss.
14. PETROLEUM AND NATURAL GAS SALES
The Company's petroleum and natural gas sales from contracts with customers for each reportable segment is set forth in the
following table.
Years Ended December 31
2020
2019
Light oil and condensate
$
296,125 $
327,460 $
623,585 $
538,487 $
600,163 $ 1,138,650
Canada
U.S.
Total
Canada
U.S.
Total
Heavy oil
NGL
Natural gas sales
236,235
6,037
33,344
—
236,235
500,187
—
500,187
34,845
41,431
40,882
74,775
8,430
30,620
60,647
67,385
69,077
98,005
Total petroleum and natural gas sales
$
571,741 $
403,736 $
975,477 $ 1,077,724 $
728,195 $ 1,805,919
Included in accounts receivable at December 31, 2020 is $81.3 million (December 31, 2019 - $138.0 million) of accrued
petroleum and natural gas sales related to deliveries for periods ended prior to the reporting date.
15.
INCOME TAXES
The provision for income taxes has been computed as follows:
Net loss before income taxes
Expected income taxes at the statutory rate of 25.42%(1) (2019 – 26.72%)
(Increase) decrease in income tax recovery resulting from:
Share-based compensation
Effect of foreign exchange
Effect of change in income tax rates
Effect of rate adjustments for foreign jurisdictions
Effect of change in deferred tax benefit not recognized
Effect of U.S. tax change
Adjustments and assessments
Income tax recovery
Years Ended December 31
2020
$
(2,599,357) $
(660,757)
1,834
1,017
10,969
22,375
444,117
19,807
245
2019
(78,921)
(21,088)
4,247
(8,155)
(6,098)
(27,785)
(7,563)
—
(20)
$
(160,393) $
(66,462)
(1) On October 20, 2020 the Alberta government enacted legislation to decrease the corporate income tax rate from 10% to 8% effective July 1,
2020.
At December 31, 2020, a deferred tax asset of $469.7 million remains unrecognized due to uncertainty surrounding future
commodity prices and future capital gains (December 31, 2019 - $28.0 million). These deferred income tax assets relate to
deductible temporary differences of $854.2 million, capital losses of $237.9 million and non-capital losses of $1,015.2 million,
which expire from 2034 to 2040.
Baytex Energy Corp. 2020 Annual Report
69
In June 2016, certain indirect subsidiary entities received reassessments from the Canada Revenue Agency (the “CRA”) that
denied $591 million of non-capital loss deductions that relate to the calculation of income taxes for the years 2011 through 2015.
In September 2016, Baytex filed notices of objection with the CRA appealing each reassessment received. There has been no
change in the status of these reassessments since an Appeals Officer was assigned to the Company's file in July 2018. Baytex
remains confident that the original tax filings are correct and intends to defend those tax filings through the appeals process.
On April 7, 2020, the U.S. Department of the Treasury and the IRS published final regulations addressing “anti-hybrid” rules
under section 267A of the U.S. tax code and thus became substantially enacted. Pursuant to these regulations, the Company is
no longer entitled to certain tax benefits previously recognized during 2019. Accordingly, a charge against deferred income taxes
in the amount of $19.8 million was recorded in 2020.
A continuity of the net deferred income tax liability is detailed in the following tables:
As at
Taxable temporary differences:
January 1, 2020
Recognized in
Net Income
Foreign
Currency
Translation
Adjustment
December 31,
2020
Petroleum and natural gas properties
$
(881,994) $
378,321 $
1,048 $
(502,625)
Financial derivatives
Other
Deductible temporary differences:
Asset retirement obligations
Financial derivatives
Non-capital losses
Other
—
(2,403)
—
(18,839)
164,523
802
386,717
97,047
23,432
4,608
(141,468)
(85,087)
—
(1,135)
(115)
—
(3,735)
(8,255)
—
(22,377)
187,840
5,410
241,514
3,705
Net deferred income tax liability (1)
$
(235,308) $
160,967 $
(12,192) $
(86,533)
(1) Non-capital loss carry-forwards at December 31, 2020 totaled $2,165.2 million and expire from 2034 to 2040.
As at
Taxable temporary differences:
January 1, 2019
Recognized in
Net Loss
Foreign
Currency
Translation
Adjustment
December 31,
2019
Petroleum and natural gas properties
$
(954,506) $
48,995 $
23,517 $
(881,994)
Financial derivatives
Other
Deductible temporary differences:
Asset retirement obligations
Financial derivatives
Non-capital losses
Finance costs
(21,486)
(3,045)
172,359
—
399,699
96,143
21,486
5,192
(7,364)
802
(1,460)
904
—
(4,550)
(472)
—
(11,522)
—
—
(2,403)
164,523
802
386,717
97,047
Net deferred income tax liability (1)
$
(310,836) $
68,555 $
6,973 $
(235,308)
(1) Non-capital loss carry-forwards at December 31, 2019 totaled $1,714.6 million and expire from 2034 to 2039.
70
Baytex Energy Corp. 2020 Annual Report
16. FINANCING AND INTEREST
Interest on credit facilities
Interest on long-term notes
Interest on lease obligations
Non-cash financing
Accretion of asset retirement obligations (note 10)
Early redemption expense (note 9)
Financing and interest
17. FOREIGN EXCHANGE
Unrealized foreign exchange loss - intercompany notes (1)
Unrealized foreign exchange gain - long-term notes
Realized foreign exchange (gain) loss
Foreign exchange loss (gain)
$
Years Ended December 31
2020
15,256 $
90,830
448
6,617
8,978
3,312
2019
20,376
86,431
610
4,735
13,713
—
$
125,441 $
125,865
Years Ended December 31
2020
31,617 $
(22,385)
(544)
8,688 $
2019
—
(62,753)
966
(61,787)
$
$
(1) During 2020, a series of intercompany notes totaling US$751.0 million were issued from a Canadian subsidiary to a U.S. subsidiary. These
notes are eliminated upon consolidation within the Statement of Financial Position and are revalued at the relevant foreign exchange rate at
each period end. Foreign exchange gains or losses incurred within the Canadian subsidiary are recognized in unrealized foreign exchange
gain or loss whereas those within the U.S. subsidiary are recognized in other comprehensive income.
18. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
The Company's financial assets and liabilities are comprised of cash, trade and other receivables, trade and other payables,
financial derivatives, credit facilities and long-term notes. The carrying value of cash, trade and other receivables and trade and
other payables approximates their fair value due to the short period to maturity of these instruments. The fair value of the credit
facilities is equal to the principal amount outstanding as the credit facilities bear interest at floating rates and credit spreads that
are indicative of market rates. The fair value of the long-term notes is determined based on market prices. The fair value of
financial derivatives is measured with reference to quoted market prices, estimated of future volatility and interest rates available
at period end.
Baytex Energy Corp. 2020 Annual Report
71
The carrying value and fair value of the Company's financial instruments carried on the consolidated statements of financial
position are classified into the following categories:
December 31, 2020
December 31, 2019
Carrying value
Fair value Carrying value
Fair value
Fair Value
Measurement
Hierarchy
Financial Assets
FVTPL
Financial Derivatives
Total
Financial assets at amortized cost
Cash
Trade and other receivables
Total
Financial Liabilities
FVTPL
Financial Derivatives
Total
Financial liabilities at amortized cost
$
$
$
$
$
$
5,057 $
5,057 $
5,057 $
5,057 $
5,433 $
5,433 $
5,433
5,433
Level 2
— $
— $
5,572 $
107,477
107,477
173,762
107,477 $
107,477 $
179,334 $
5,572
173,762
179,334
—
—
(26,792) $
(26,792) $
(26,792) $
(26,792) $
(8,668) $
(8,668) $
(8,668)
(8,668)
Level 2
Trade and other payables
$
(155,955) $
(155,955) $
(207,454) $
(207,454)
Credit Facilities
Long-term notes
Total
(649,221)
(1,132,868)
(651,173)
(761,129)
(505,412)
(506,471)
(1,328,175)
(1,290,817)
Level 1
$
(1,938,044) $
(1,568,257) $
(2,041,041) $
(2,004,742)
—
—
There were no transfers between Level 1 and Level 2 in during the years ended December 31, 2020 or 2019.
Financial Risk
Baytex is exposed to a variety of financial risks, including market risk, liquidity risk and credit risk. The Company's process to
mitigate these risks is described below.
Market Risk
Market risk is the risk that the fair value or future cash flows of financial assets or liabilities will fluctuate due to movements in
market prices. Market risk is comprised of foreign currency risk, interest rate risk and commodity price risk.
Foreign Currency Risk
Baytex is exposed to fluctuations in foreign exchange rates as a result of the U.S. dollar portion of its credit facilities, long-term
notes, intercompany notes, crude oil sales based on U.S. dollar benchmark prices and commodity financial derivative contracts
that are settled in U.S. dollars. The Company's net income or loss, comprehensive income or loss and cash flow will therefore be
impacted by fluctuations in foreign exchange rates.
To manage the impact of foreign exchange rate fluctuations, the Company may enter into agreements to fix the Canadian to U.S.
dollar exchange rate. At December 31, 2020 and 2019, the Company did not have any currency derivative contracts outstanding.
A $0.01 increase or decrease in the CAD/USD foreign exchange rate on the revaluation of outstanding U.S. dollar denominated
assets and liabilities, would impact net income or loss before income taxes by approximately $1.8 million.
72
Baytex Energy Corp. 2020 Annual Report
The carrying amounts of the Company’s U.S. dollar denominated monetary assets and liabilities recorded in entities with a
Canadian dollar functional currency at the reporting date are as follows:
U.S. dollar denominated
US$759,508
US$8,733
US$934,731
US$841,961
Assets
Liabilities
December 31, 2020
December 31, 2019
December 31, 2020
December 31, 2019
Interest Rate Risk
The Company's interest rate risk arises from borrowing at floating rates under the Revolving Facilities and Term Loan (note 8).
Based on the principal outstanding on the Credit Facilities, as at December 31, 2020, a change of 100 basis points in interest
rates would have an impact on net income or loss before income taxes of approximately $6.5 million.
Commodity Price Risk
Baytex utilizes financial derivative contracts or physical delivery contracts to manage the risk associated with changes in
commodity prices. The use of derivatives is governed by a Risk Management Policy approved by the Board of Directors of
Baytex which sets out limits on the use of derivatives. Baytex does not use financial derivatives for speculative purposes.
Baytex's financial derivative contracts are subject to master netting agreements that create a legally enforceable right to offset by
the counterparty the related financial assets and financial liabilities.
When assessing the potential impact of crude oil price changes on the crude oil financial derivative contracts outstanding as at
December 31, 2020, a US$1.00/bbl change in the underlying benchmark crude oil prices would impact net income or loss before
income taxes by approximately $18.9 million.
When assessing the potential impact of natural gas price changes on the financial derivative contracts outstanding as at
December 31, 2020, a US$0.25 change in the underlying benchmark natural gas prices would impact net income or loss before
income taxes by approximately $4.6 million.
Baytex Energy Corp. 2020 Annual Report
73
Oil
Basis swap
Basis swap
Basis swap (4)
Basis swap (4)
Basis swap
Basis swap (4)
Fixed - Sell
3-way option (2)
3-way option (2)
3-way option (2)
3-way option (2)
3-way option (2)
3-way option (2)(4)
Swaption (3)
Swaption (3)
Natural Gas
Fixed - Sell
Fixed - Sell
Fixed - Sell
Fixed - Sell
3-way option (2)
3-way option (2)(4)
Financial Derivative Contracts
Baytex had the following commodity financial derivative contracts outstanding as at February 24, 2021.
Period
Volume
Price/Unit (1)
Jan 2021 to Jun 2021
Jan 2021 to Dec 2021
Apr 2021 to Dec 2021
Jan 2022 to Dec 2022
Jan 2021 to Dec 2021
Mar 2021 to Dec 2021
Jan 2021 to Dec 2021
Jan 2021 to Dec 2021
Jan 2021 to Dec 2021
Jan 2021 to Dec 2021
2,000 bbl/d
7,000 bbl/d
1,000 bbl/d
6,000 bbl/d
6,000 bbl/d
1,500 bbl/d
4,000 bbl/d
500 bbl/d
1,500 bbl/d
3,500 bbl/d
WTI less US$13.75/bbl
WTI less US$13.68/bbl
WTI less US$11.50/bbl
WTI less US$12.76/bbl
WTI less US$5.17/bbl
WTI less US$4.50/bbl
US$45.00/bbl
US$35.00/US$45.00/US$49.03
US$35.00/US$45.00/US$49.10
US$35.00/US$45.00/US$49.50
Jan 2021 to Dec 2021
10,000 bbl/d
US$35.00/US$45.00/US$55.00
Jan 2021 to Dec 2021
Jan 2022 to Dec 2022
Jan 2022 to Dec 2022
Jan 2022 to Dec 2022
2,000 bbl/d
1,500 bbl/d
5,000 bbl/d
5,000 bbl/d
US$37.00/US$42.50/US$48.00
US$40.00/US$50.00/US$58.10
US$53.00/bbl
US$54.00/bbl
Index
WCS
WCS
WCS
WCS
MSW
MSW
WTI
WTI
WTI
WTI
WTI
WTI
WTI
WTI
WTI
Jan 2021 to Jun 2021
Jan 2021 to Dec 2021
Jan 2021 to Dec 2021
3,000 GJ/d
16,000 GJ/d
2,500 GJ/d
$2.71/GJ
$2.36/GJ
$2.40/GJ
Jan 2021 to Dec 2021
12,000 mmbtu/d
US$2.70/mmbtu
Jan 2022 to Dec 2022
2,500 mmbtu/d
US$2.25/US$2.75/US$3.06
Jan 2022 to Dec 2022
2,500 mmbtu/d
US$2.65/US$2.90/US$3.40
AECO 7A
AECO 7A
AECO 5A
NYMEX
NYMEX
NYMEX
(1) Based on the weighted average price per unit for the period.
(2) Producer 3-way option consists of a sold call, a bought put and a sold put. To illustrate, in a US$35.00/US$45.00/US$55.00 contract, Baytex
receives WTI plus US$10.00/bbl when WTI is at or below US$35.00/bbl; Baytex receives US$45.00/bbl when WTI is between US$35.00/bbl
and US$45.00/bbl; Baytex receives the market price when WTI is between US$45.00/bbl and US$55.00/bbl; and Baytex receives
US$55.00/bbl when WTI is above US$55.00/bbl.
(3) For these contracts, the counterparty has the right, if exercised on December 31, 2021, to enter a swap transaction for the remaining term,
notional volume and fixed price per unit indicated above.
(4) Contracts entered subsequent to December 31, 2020.
The following table sets forth the realized and unrealized gains and losses recorded on financial derivatives.
Realized financial derivatives gain
Unrealized financial derivatives loss
Financial derivatives (gain) loss
Liquidity Risk
Years Ended December 31
2020
(47,836) $
18,500
(29,336) $
2019
(75,620)
82,817
7,197
$
$
Liquidity risk is the risk that Baytex will encounter difficulty in meeting obligations associated with financial liabilities. Baytex
manages its liquidity risk through cash and debt management. Such strategies include monitoring forecasted and actual cash
flows from operating, financing and investing activities, available credit under existing banking arrangements, opportunities to
issue additional common shares as well as reducing capital expenditures.
As at December 31, 2020, Baytex had available unused credit facilities in the amount of $367.2 million (December 31, 2019 -
$523.8 million).
74
Baytex Energy Corp. 2020 Annual Report
The timing of cash outflows relating to financial liabilities as at December 31, 2020 is outlined in the table below:
Total
Less than
1 year
1-3 years
3-5 years Beyond 5 years
Trade and other payables
$
155,955 $
155,955 $
— $
Financial derivatives
Credit facilities (1)(2)
Long-term notes (2)
Interest on long-term notes (3)
Lease obligations (2)
26,792
651,173
1,147,950
446,854
11,850
26,792
—
—
84,502
4,504
—
—
—
169,004
4,302
— $
—
651,173
510,200
123,479
3,044
—
—
—
637,750
69,869
—
$
2,440,574 $
271,753 $
173,306 $
1,287,896 $
707,619
(1) At December 31, 2019, the credit facilities were set to mature on April 2, 2021. On March 3, 2020, Baytex amended the credit facilities to
extend maturity to April 2, 2024 which will automatically be extended to June 4, 2024 providing the Company has either refinanced or has
the ability to repay the outstanding 2024 long-term notes with existing credit capacity as of April 1, 2024.
(2) Principal amount of instruments. On February 5, 2020, Baytex issued US$500 million principal amount of 8.75% senior unsecured notes
due 2027. On February 20, 2020 Baytex completed the redemption of the US$400 million principal amount of senior unsecured notes due
2021 and, on March 5, 2020, completed the redemption of $300 million principal amount of 6.625% senior unsecured notes due 2022 (note
9).
(3) Excludes interest on credit facilities as interest payments on credit facilities fluctuate based on amounts outstanding and the prevailing
interest rate at the time of borrowing.
Credit Risk
Credit risk is the risk that a counterparty to a financial asset will default resulting in Baytex incurring a loss. As at December 31,
2020, the Company is exposed to credit risk with respect to its trade and other receivables and financial derivatives. Baytex
manages these risks through the selection and monitoring of credit-worthy counterparties.
Most of the Company's trade and other receivables relate to petroleum and natural gas sales. Baytex reviews its exposure to
individual entities on a regular basis and manages its credit risk by entering into sales contracts after reviewing the
creditworthiness of the entity. Letters of credit or parental guarantees may be obtained prior to the commencement of business
with certain counterparties. Credit risk may also arise from financial derivative instruments. The maximum exposure to credit risk
is equal to the carrying value of the financial assets. The Company considers all financial assets that are not impaired or past
due to be of good credit quality.
The majority of the Company's credit exposure on trade and other receivables at December 31, 2020 relates to accrued
revenues. Accounts receivable from purchasers of the Company's petroleum and natural gas sales are typically collected on the
25th day of the month following production. Joint interest receivables are typically collected within one to three months following
production. Included in trade and other receivables at December 31, 2020 is $81.3 million (December 31, 2019 - $138.0 million)
of accrued petroleum and natural gas sales.
Should the Company determine that the ultimate collection of a receivable is in doubt, the carrying amount of trade and other
receivables is reduced by adjusting the allowance for doubtful accounts and a charge to net income or loss. If the Company
subsequently determines the accounts receivable is uncollectible, the receivable and allowance for doubtful accounts are
adjusted accordingly. As at December 31, 2020, allowance for doubtful accounts was $2.0 million (December 31, 2019 - $1.6
million).
In determining whether amounts past due are collectible, the Company will assess the nature of the past due amounts as well as
the credit worthiness and past payment history of the counterparty. As at December 31, 2020, accounts receivable that Baytex
has deemed past due (more than 90 days) but not impaired was $1.6 million (December 31, 2019 - $2.7 million). Baytex has
estimated the lifetime expected credit loss as at and for the year ended December 31, 2020 to be nominal.
The Company's trade and other receivables, net of the allowance for doubtful accounts, were aged as follows at December 31,
2020.
Trade and Other Receivables Aging
Current (less than 30 days)
31-60 days
61-90 days
Past due (more than 90 days)
December 31, 2020
December 31, 2019
104,210 $
169,500
1,493
220
1,554
1,199
342
2,721
107,477 $
173,762
$
$
Baytex Energy Corp. 2020 Annual Report
75
19. SUPPLEMENTAL INFORMATION
Changes in Non-Cash Working Capital Items
Trade and other receivables
Trade and other payables
Changes in non-cash working capital related to:
Operating activities
Investing activities
Foreign currency translation on non-cash working capital
Income Statement Presentation
Years Ended December 31
2020
66,285 $
(51,499)
14,786 $
48,758 $
(32,031)
(1,941)
14,786 $
2019
(62,198)
(50,660)
(112,858)
(52,070)
(62,485)
1,697
(112,858)
$
$
$
$
Baytex's consolidated statements of income or loss and comprehensive income or loss are prepared primarily according to the
nature of expense, with the exception of employee compensation costs which are included in both operating expense and
general and administrative expense line items.
The following table details the amount of total employee compensation costs included in the operating expense and general and
administrative expense.
Operating
General and administrative
Total employee compensation costs
20. COMMITMENTS
Years Ended December 31
2020
9,065 $
22,802
31,867 $
2019
12,918
33,728
46,646
$
$
Baytex has a number of financial obligations that are incurred in the ordinary course of business. These obligations are of a
recurring nature and impact the Company’s cash flow from operations in an ongoing manner. A significant portion of these
obligations will be funded by adjusted funds flow. These obligations as of December 31, 2020, and the expected timing of funding
of these obligations, are noted in the table below.
Processing agreements
Transportation agreements
Total
$
$
Total
6,361
98,406
Less than
1 year
836
16,698
104,767 $
17,534 $
41,671 $
25,377 $
1-3 years
3-5 years Beyond 5 years
1,320
40,351
474
24,903
3,731
16,454
20,185
Baytex also has ongoing obligations related to the abandonment and reclamation of well sites and facilities which have reached
the end of their economic lives. The present value of the future estimated abandonment and reclamation costs are included in
the asset retirement obligations presented in the statements of financial position. Programs to abandon and reclaim wellsites and
facilities are undertaken regularly in accordance with applicable legislative requirements.
76
Baytex Energy Corp. 2020 Annual Report
21. RELATED PARTIES
Transactions with key management personnel and directors are noted in the table below.
Short-term employee benefits
Share-based compensation
Termination payments
Total compensation for key management personnel
22. CAPITAL MANAGEMENT
Years Ended December 31
2020
4,295 $
4,080
—
8,375 $
2019
6,202
9,188
2,208
17,598
$
$
The Company's capital management objective is to maintain financial flexibility and sufficient sources of liquidity to execute its
capital programs, while meeting short and long-term commitments. Baytex strives to actively manage its capital structure in
response to changes in economic conditions. At December 31, 2020, the Company's capital structure was comprised of
shareholders' capital, long-term notes, trade and other receivables, trade and other payables and the credit facilities.
During 2020, Baytex took additional action to protect financial liquidity in response to lower oil prices and the global economic
instability related to COVID-19. The Company's 2020 exploration and development expenditures were reduced by moderating
the pace of activity in the U.S. and suspending drilling and completion operations in Canada. Certain high cost, low margin,
production was shut-in for a portion of 2020 when netbacks were challenged by low commodity prices. Baytex remains
committed to cost saving initiatives which resulted in lower operating expenses and general administrative costs during 2020.
The capital intensive nature of Baytex's operations requires the maintenance of adequate sources of liquidity to fund ongoing
exploration and development. Baytex's capital resources consist primarily of adjusted funds flow, available credit facilities and
proceeds received from the divestiture of oil and gas properties. The Company's adjusted funds flow depends on a number of
factors, including commodity prices, production and sales volumes, royalties, operating expenses, taxes and foreign exchange
rates. In order to manage its capital structure and liquidity, Baytex may from time to time issue equity or debt securities, enter into
business transactions including the sale of assets or adjust capital spending to manage current and projected debt levels. There
is no certainty that any of these additional sources of capital would be available if required.
At December 31, 2020, Baytex was in compliance with all of the covenants contained in the Credit Facilities and had unused
capacity of $367.2 million (December 31, 2019 - $523.8 million).
Baytex considers adjusted funds flow a key measure that provides a more complete understanding of operating performance and
the Company's ability to generate funds for exploration and development expenditures, debt repayment, settlement of
abandonment obligations and potential future dividends. Baytex eliminates settlements of abandonment obligations from cash
flow from operations as the amounts can be discretionary and may vary from period to period depending on the Company's
capital programs and the maturity of its operating areas. The settlement of abandonment obligations are managed through the
capital budgeting process which considers available adjusted funds flow. Changes in non-cash working capital are eliminated in
the determination of adjusted funds flow as the timing of collection, payment and incurrence is variable and by excluding them
from the calculation Baytex is able to provide a more meaningful measure of cash flow on a continuing basis.
Adjusted funds flow should not be construed as an alternative to performance measures determined in accordance with IFRS,
such as cash flow from operating activities and net income or loss.
Adjusted funds flow does not have any standardized meaning prescribed by IFRS and may not be comparable with the
calculation of similar measures for other entities. It is reconciled to the nearest measure determined in accordance with IFRS,
cash flow from operating activities, as set forth below.
Cash flow from operating activities
Change in non-cash working capital
Asset retirement obligations settled
Adjusted funds flow
Years Ended December 31
2020
353,096 $
(48,758)
7,168
311,506 $
2019
834,939
52,070
15,417
902,426
$
$
Baytex Energy Corp. 2020 Annual Report
77
The Company believes that net debt assists in providing a more complete understanding of its financial position and provides a
key measure to assess liquidity. Net debt is calculated based on the principal amounts of the credit facilities and long-term notes
outstanding, including trade and other payables, cash, and trade and other receivables. The principal amounts of the credit
facilities and long-term notes outstanding are used in the calculation of net debt as these amounts represent the Company's total
repayment obligation at maturity. The carrying amount of debt issue costs associated with the credit facilities and long-term notes
are excluded on the basis that these amounts have already been paid by Baytex at inception of the contract and do not represent
an additional source of liquidity or repayment obligation.
Net debt does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar
measure for other entities. The computation of net debt is set forth below.
Credit facilities - principal
Long-term notes - principal
Trade and other payables
Cash
Trade and other receivables
Net debt
December 31, 2020
December 31, 2019
$
$
651,173 $
1,147,950
155,955
—
(107,477)
1,847,601 $
506,471
1,337,200
207,454
(5,572)
(173,762)
1,871,791
78
Baytex Energy Corp. 2020 Annual Report
PETROLEUM AND NATURAL GAS RESERVES AS AT DECEMBER 31, 2020
Baytex's year-end 2020 proved and probable reserves were evaluated by McDaniel & Associates Consultants Ltd. (“McDaniel”),
an independent qualified reserves evaluator. All of our oil and gas properties were evaluated in accordance with National
Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” (“NI 51-101”) and the Canadian Oil and Gas Evaluation
Handbook (the “COGE Handbook”) using the average commodity price forecasts and inflation rates of McDaniel, GLJ Petroleum
Consultants (“GLJ”) and Sproule Associates Limited (“Sproule”) as of January 1, 2021.
Reserves associated with our thermal heavy oil projects at Gemini (Cold Lake) and Kerrobert have been classified as bitumen.
Complete reserves disclosure will be included in our Annual Information Form for the year ended December 31, 2020, which will
be filed on or before March 31, 2021.
The following table sets forth our gross and net reserves volumes at December 31, 2020 by product type and reserves category.
Please note that the data in the table may not add due to rounding.
Reserves Summary
Reserves Summary
Gross (1)
Proved producing
Proved developed non-producing
Proved undeveloped
Total proved
Total probable
Proved plus probable
Net (2)
Proved producing
Proved developed non-producing
Proved undeveloped
Total proved
Total probable
Proved plus probable
Notes:
Light and
Medium Oil
(mbbls)
Tight Oil
(mbbls)
Heavy
Oil
(mbbls)
Bitumen
(mbbls)
Total Oil
(mbbls)
20,404
61
31,601
52,067
25,688
77,755
19,106
59
29,630
48,795
23,461
72,256
23,473
38
29,805
53,316
24,642
77,958
17,445
28
22,371
39,844
18,777
58,621
19,917
1,997
13,499
35,412
30,544
65,956
18,404
1,895
12,385
32,684
27,640
60,324
1,144
160
4,433
5,737
46,093
51,830
1,027
152
4,213
5,393
40,064
45,456
64,938
2,255
79,339
146,532
126,967
273,499
55,983
2,135
68,598
126,716
109,941
236,657
Natural
Gas
Liquids (3)
(mbbls)
31,669
639
40,167
72,475
32,760
Conventional
Natural Gas (4)
(mmcf)
Shale
Gas
(mmcf)
43,384
15,072
29,438
87,894
86,778
97,321
473
128,541
226,334
96,852
Total (5)
(mboe)
120,057
5,485
145,835
271,378
190,332
105,235
174,671
323,186
461,710
23,635
504
29,865
54,003
24,853
78,856
40,568
13,080
26,071
79,270
80,679
72,440
350
95,639
168,429
73,061
98,452
4,877
118,748
222,077
160,417
160,398
241,490
382,495
(1)
“Gross” reserves means the total working interest share of remaining recoverable reserves owned by Baytex before deductions of royalties payable to others.
(2)
“Net” reserves means Baytex's gross reserves less all royalties payable to others plus royalty interest reserves.
(3) Natural Gas Liquids includes condensate.
(4) Conventional Natural Gas includes associated, non-associated and solution gas.
(5) Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. BOEs may be misleading,
particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Baytex Energy Corp. 2020 Annual Report
79
Reserves Reconciliation
The following table reconciles the year-over-year changes in our gross reserves volumes by product type and reserves category.
Please note that the data in the table may not add due to rounding.
Proved Reserves – Gross Volumes (1) (Forecast Prices)
December 31, 2019
Extensions
Technical Revisions (2)
Acquisitions
Dispositions
Economic Factors
Production
December 31, 2020
Light and
Medium Oil
(mbbls)
60,619
Heavy
Tight Oil
(mbbls)
55,562
Oil Bitumen
(mbbls)
11,799
(mbbls)
51,311
2,840
(1,275)
16
(15)
(3,421)
(6,698)
52,067
1,618
1,780
—
—
(592)
(5,052)
53,316
160
2,462
—
(5)
(11,698)
(6,818)
35,412
3,027
(1,224)
—
—
(6,945)
(920)
Total Oil
(mbbls)
179,291
7,645
1,743
16
(20)
(22,655)
(19,488)
1,541
(758)
1
—
(1,748)
(4,499)
72,475
Natural
Gas
Liquids (3)
(mbbls)
77,939
Conventional
Natural Gas (4)
(mmcf)
104,506
Shale
Gas
(mmcf)
234,162
4,038
7,225
—
—
(2,877)
(16,213)
12,937
9,360
19
(38)
(23,824)
(15,066)
5,737
146,532
87,894
226,334
Probable Reserves – Gross Volumes (1) (Forecast Prices)
December 31, 2019
Extensions
Technical Revisions (2)
Acquisitions
Dispositions
Economic Factors
Production
December 31, 2020
Light and
Medium Oil
(mbbls)
31,218
Heavy
Tight Oil
(mbbls)
24,139
Oil Bitumen
(mbbls)
53,743
(mbbls)
37,805
(1,937)
(3,643)
3
(92)
139
—
25,688
1,291
(648)
—
—
(141)
—
24,642
244
(1,634)
—
(4)
(5,867)
—
30,544
696
(366)
—
—
(7,980)
—
46,093
Proved Plus Probable Reserves – Gross Volumes (1) (Forecast Prices)
Light and
Medium Oil
(mbbls)
91,837
Heavy
Tight Oil
(mbbls)
79,701
Oil Bitumen
(mbbls)
65,542
(mbbls)
89,116
903
(4,917)
19
(107)
(3,282)
(6,698)
77,755
2,909
1,132
—
—
(733)
(5,052)
77,958
404
827
—
(8)
(17,565)
(6,818)
3,723
(1,590)
—
—
(14,925)
(920)
December 31, 2019
Extensions
Technical Revisions (2)
Acquisitions
Dispositions
Economic Factors
Production
December 31, 2020
Notes:
Natural
Gas
Liquids (3)
(mbbls)
35,654
Conventional
Natural Gas (4)
(mmcf)
99,816
908
(3,954)
—
(4)
157
—
32,760
(11,371)
(10,854)
3
(348)
9,531
—
86,778
Natural
Gas
Liquids (3)
(mbbls)
113,592
2,449
(4,712)
1
(4)
(1,592)
(4,499)
Conventional
Natural Gas (4)
(mmcf)
204,323
1,565
(1,494)
22
(386)
(14,293)
(15,066)
Total Oil
(mbbls)
146,905
294
(6,291)
3
(96)
(13,849)
—
126,967
Total Oil
(mbbls)
326,196
7,939
(4,548)
19
(116)
(36,505)
(19,488)
Shale
Gas
(mmcf)
99,739
5,283
(6,929)
—
—
(1,240)
—
96,852
Shale
Gas
(mmcf)
333,901
9,320
296
—
—
(4,118)
(16,213)
65,956
51,830
273,499
105,235
174,671
323,186
461,710
(1)
“Gross” reserves means the total working interest share of remaining recoverable reserves owned by Baytex before deductions of royalties payable to others.
(2) Positive and negative revisions in heavy oil, bitumen, light and medium oil and tight oil are due to variations in performance versus previous forecasts in our
Viking, Eagle Ford, Peace River and Lloydminster assets. Technical revisions for conventional natural gas are a combination of performance revisions in our
Deep Basin assets and performance revisions for solution gas (classified as conventional natural gas) from our light and heavy oil properties. Positive revisions
for shale gas are attributed to improved performance in the Duvernay and Eagle Ford assets.
(3) Natural gas liquids include condensate.
(4) Conventional natural gas includes associated, non-associated and solution gas.
(5) Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. BOEs may be misleading,
particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
80
Baytex Energy Corp. 2020 Annual Report
Total (5)
(mboe)
313,674
12,015
3,749
20
(26)
(28,854)
(29,200)
271,378
Total (5)
(mboe)
215,818
187
(13,208)
4
(158)
(12,311)
—
190,332
Total (5)
(mboe)
529,492
12,202
(9,460)
24
(184)
(41,165)
(29,200)
Future Development Costs
The following table sets forth future development costs deducted in the estimation of the future net revenue attributable to the
reserves categories noted below.
Future Development Costs ($ millions)
2021
2022
2023
2024
2025
Remainder
Total FDC undiscounted
Proved
Reserves
276
439
477
432
420
50
2,094
Proved Plus
Probable Reserves
283
491
560
538
580
1,153
3,606
F&D and FD&A Costs – including future development costs
Based on the evaluation of our petroleum and natural gas reserves prepared by McDaniel, the efficiency of our capital program is
summarized in the following table.
millions except for per boe amounts
Proved plus Probable Reserves
Finding & Development Costs
Exploration and development expenditures
Net change in Future Development Costs
Gross Reserves additions (mmboe)
F&D Costs ($/boe)
Finding, Development & Acquisition (“FD&A”) Costs
Exploration and development expenditures and net acquisitions
Net change in Future Development Costs
Gross Reserves additions (mmboe)
FD&A Costs ($/boe)
Proved Reserves
Finding & Development Costs
Exploration and development expenditures
Net change in Future Development Costs
Gross Reserves additions (mmboe)
F&D Costs ($/boe)
Finding, Development & Acquisition Costs
Exploration and development expenditures and net acquisitions
Net change in Future Development Costs
Gross Reserves additions (mmboe)
FD&A Costs ($/boe)
Proved Developed Producing Reserves
Finding & Development Costs
Exploration and development expenditures
Gross Reserves additions (mmboe)
F&D Costs ($/boe)
Finding, Development & Acquisition Costs
Exploration and development expenditures and net acquisitions
Gross Reserves additions (mmboe)
FD&A Costs ($/boe)
2020
2019
2018
3 Year
$280.3
($705.9)
(38.4)
$11.08
$280.2
($709.3)
(38.6)
$11.12
$280.3
($464.4)
(13.1)
$14.06
$280.2
($464.4)
(13.1)
$14.07
$280.3
7.7
$36.63
$280.2
7.6
$36.64
$552.3
$96.7
39.8
$16.30
$554.5
$79.9
38.6
$16.42
$552.3
($90.4)
35.8
$12.92
$554.5
($107.2)
34.7
$12.88
$552.3
42.5
$13.04
$554.5
42.5
$13.04
$495.7
$132.3
31.2
$20.11
$2,099.6
$1,064.5
123.9
$25.55
$495.7
$117.4
17.5
$35.05
$2,099.6
$987.4
88.4
$34.91
$495.7
31.3
$15.82
$2,099.6
63.7
$32.95
$1,328.3
($476.8)
32.6
$26.09
$2,934.2
$435.1
123.9
$27.19
$1,328.3
($437.4)
40.2
$22.18
$2,934.2
$415.8
110.0
$30.44
$1,328.3
81.3
$16.33
$2,934.2
113.9
$25.76
Baytex Energy Corp. 2020 Annual Report
81
Reserves Life Index
The following table sets forth our reserves life index, which is calculated by dividing our proved and proved plus probable reserves
at year-end 2020 by annualized Q4/2020 production.
Q4/2020
Production
57,788
76,116
70,475
Reserves Life Index (years)
Proved
10.4
11.3
10.5
Proved Plus
Probable
18.0
17.9
17.9
Crude Oil and NGL (bbl/d)
Natural Gas (mcf/d)
Oil Equivalent (boe/d)
Forecast Prices and Costs
The following table summarizes the forecast prices used in preparing the estimated reserves volumes and the net present values
of future net revenues at December 31, 2020. The estimated future net revenue to be derived from the production of the reserves
is based on the following average of the price forecasts of McDaniel, GLJ and Sproule as of January 1, 2020.
Year
2020 act.
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
WTI Crude Oil
US$/bbl
39.20
Edmonton Light
Crude Oil
$/bbl
45.00
47.17
50.17
53.17
54.97
56.07
57.19
58.34
59.50
60.69
61.91
55.76
59.89
63.48
65.76
67.13
68.53
69.95
71.40
72.88
74.34
Western
Canadian Select
$/bbl
35.35
44.63
48.18
52.10
54.10
55.19
56.29
57.42
58.57
59.74
60.93
Henry Hub
US$/MMbtu
2.05
AECO Spot
$/MMbtu
2.25
2.83
2.87
2.90
2.96
3.02
3.08
3.14
3.20
3.26
3.33
2.78
2.70
2.61
2.65
2.70
2.76
2.81
2.87
2.92
2.98
Thereafter
Escalation rate of 2.0%
Net Present Value of Reserves (1) (Forecast Prices and Costs)
Inflation Rate
%/Yr
Exchange Rate
$US/$Cdn
0.2
0.0
1.3
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
0.745
0.768
0.765
0.763
0.763
0.763
0.763
0.763
0.763
0.763
0.763
0.763
The following table summarizes the McDaniel estimate of the net present value before income taxes of the future net revenue
attributable to our reserves.
Reserves at December 31, 2020 ($ millions, discounted at)
Proved developed producing
Proved developed non-producing
Proved undeveloped
Total proved
Probable
Total Proved Plus Probable (before tax)
Note:
0%
1,089
69
2,221
3,379
3,374
6,753
5%
1,203
59
1,443
2,704
1,837
4,542
10%
1,118
51
972
2,141
1,138
3,279
15%
1,018
46
671
1,735
771
2,505
(1)
Includes abandonment, decommissioning and reclamation costs for all producing and nonproducing wells and facilities.
82
Baytex Energy Corp. 2020 Annual Report
Net Asset Value (Forecast Prices and Costs)
Our estimated net asset value is based on the estimated net present value of all future net revenue from our reserves, before
income taxes, as estimated by McDaniel at year-end, plus the estimated value of our undeveloped land holdings, less net debt.
This calculation can vary significantly depending on the oil and natural gas price assumptions. In addition, this calculation does
not consider "going concern" value and assumes only the reserves identified in the reserves reports with no further acquisitions
or incremental development.
The following table sets forth our net asset value as at December 31, 2020.
($ millions, except per share amounts, discounted at)
Net present value of proved plus probable reserves (1)
Undeveloped land holdings (2)
Net Debt
Net Asset Value
Net Asset Value per Share (3)
Notes:
5%
4,542
130
(1,848)
2,824
5.03
10%
3,279
130
(1,848)
1,561
2.78
15%
2,505
130
(1,848)
787
1.40
(1)
Includes abandonment, decommissioning and reclamation costs for all producing and nonproducing wells and facilities.
(2) The value of undeveloped land holdings generally represents the estimated replacement cost of our undeveloped land.
(3) Based on 561.2 million common shares outstanding as at December 31, 2020.
Advisory Regarding Oil and Gas Information
The reserves information contained in this report has been prepared in accordance with NI 51-101. Complete NI 51-101 reserves disclosure will
be included in our Annual Information Form for the year ended December 31, 2020, which will be filed on or before March 31, 2021. Listed below
are cautionary statements that are specifically required by NI 51-101:
•
The term barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand
cubic feet of natural gas to one boe (6 mcf/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. Given that the value ratio based on the current price of crude oil as
compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be
misleading as an indication of value.
• With respect to finding and development costs, 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 reserves additions for that year.
•
This report contains estimates of the net present value of our future net revenue from our reserves. Such amounts do not represent the
fair market value of our reserves.
Throughout this report, “oil and NGL” refers to heavy oil, bitumen, light and medium oil, tight oil, condensate and natural gas liquids (“NGL”) product
types as defined by NI 51-101. The following table shows Baytex’s disaggregated production volumes for the three and twelve months ended
December 31, 2020. The NI 51-101 product types are included as follows: “Heavy Oil” - heavy oil and bitumen, “Light and Medium Oil” - light and
medium oil, tight oil and condensate, “NGL” - natural gas liquids and “Natural Gas” - shale gas and conventional natural gas.
Three Months Ended December 31, 2020
Twelve Months Ended December 31, 2020
Light
and
Medium
Oil
(bbl/d)
NGL
(bbl/d)
Natural
Gas
(Mcf/d)
Oil
Equivalent
(boe/d)
9
8
14
—
13,295
1,541
13,157
11,072
13,524
1,138
533
127
572
651
10,044
1,929
15,309
15,326
2,031
3,736
14,356
5,131
33,999
25,154
Heavy
Oil
(bbl/d)
10,918
10,807
—
—
—
—
Light
and
Medium
Oil
(bbl/d)
NGL
(bbl/d)
Natural
Gas
(Mcf/d)
Oil
Equivalent
(boe/d)
7
12
12
—
11,630
1,346
11,810
11,525
17,658
803
623
113
432
668
11,058
1,634
17,131
19,614
1,507
4,147
17,953
6,116
42,665
31,179
Heavy
Oil
(bbl/d)
9,853
11,289
—
—
—
—
Canada – Heavy
Peace River
Lloydminster
Canada - Light
Viking
Duvernay
Remaining Properties
United States
Eagle Ford
Total
21,725
29,568
6,495
76,116
70,475
21,142
37,056
7,340
85,463
79,781
Baytex Energy Corp. 2020 Annual Report
83
This report discloses per boe 30-day initial production volumes for two wells drilled in the Pembina Duvernay. The disaggregated 30-day initial
production volumes for the 10-16 well were 885 bbl/d Light and Medium Oil, 279 bbl/d NGL and 750 Mcf/d Natural Gas and for the 11-16 well were
601 bbl/d Light and Medium Oil, 195 bbl/d NGL and 522 Mcf/d Natural Gas.
This report contains metrics commonly used in the oil and natural gas industry, such as “finding and development costs”, “finding, development
and acquisition costs”, “net asset value”, and “reserves life index.” These terms do not have a standardized meaning and may not be comparable
to similar measures presented by other companies, and therefore should not be used to make such comparisons. Such metrics have been included
in this report to provide readers with additional measures to evaluate Baytex’s performance, however, such measures are not reliable indicators
of Baytex’s future performance and future performance may not compare to Baytex’s performance in previous periods and therefore such metrics
should not be unduly relied upon.
Finding and development costs are calculated on a per boe basis by dividing the aggregate of the change in future development costs from the
prior year for the particular reserve category and the costs incurred on exploration and development activities in the year by the change in reserves
from the prior year for the reserve category.
Finding, development and acquisition costs are calculated on a per boe basis by dividing the aggregate of the change in future development costs
from the prior year for the particular reserve category and the costs incurred on development and exploration activities and property acquisitions
(net of dispositions) in the year by the change in reserves from the year for the reserve category
Net asset value has been calculated based on the estimated net present value of all future net revenue from our reserves, before income taxes,
as estimated by McDaniel effective December 31, 2020, plus the estimated value of our undeveloped land holdings, less net debt.
Reserve life index means the reserves for the particular reserve category divided by annualized 2020 fourth quarter production.
Notice to United States Readers
The petroleum and natural gas reserves contained in this report have generally been prepared in accordance with Canadian disclosure standards,
which are not comparable in all respects to United States or other foreign disclosure standards. For example, the United States Securities and
Exchange Commission (the "SEC") requires oil and gas issuers, in their filings with the SEC, to disclose only "proved reserves", but permits the
optional disclosure of "probable reserves" (each as defined in SEC rules). Canadian securities laws require oil and gas issuers disclose their
reserves in accordance with NI 51-101, which requires disclosure of not only "proved reserves" but also "probable reserves". Additionally, NI 51-
101 defines "proved reserves" and "probable reserves" differently from the SEC rules. Accordingly, proved and probable reserves disclosed in
this report may not be comparable to United States standards. Probable reserves are higher risk and are generally believed to be less likely to be
accurately estimated or recovered than proved reserves.
In addition, under Canadian disclosure requirements and industry practice, reserves and production are reported using gross volumes, which are
volumes prior to deduction of royalty and similar payments. The SEC rules require reserves and production to be presented using net volumes,
after deduction of applicable royalties and similar payments.
Moreover, Baytex has determined and disclosed estimated future net revenue from its reserves using forecast prices and costs, whereas the SEC
rules require that reserves be estimated using a 12-month average price, calculated as the arithmetic average of the first-day-of-the-month price
for each month within the 12-month period prior to the end of the reporting period. As a consequence of the foregoing, Baytex's reserve estimates
and production volumes in this report may not be comparable to those made by companies utilizing United States reporting and disclosure
standards.
84
Baytex Energy Corp. 2020 Annual Report
ABBREVIATIONS
AECO
bbl
bbl/d
boe*
boe/d
COSO
GAAP
GJ
GJ/d
IAS
IASB
the natural gas storage facility located
at Suffield, Alberta
barrel
barrel per day
barrels of oil equivalent
barrels of oil equivalent per day
Committee of Sponsoring
Organizations of the Treadway
Commission
generally accepted accounting
principles
gigajoule
gigajoule per day
International Accounting Standard
International Accounting Standards
Board
IFRS
LLS
mbbl
mboe*
mcf
mcf/d
mmBtu
mmBtu/d
mmcf
mmcf/d
NGL
NYMEX
NYSE
TSX
WCS
WTI
International Financial Reporting
Standards
Louisiana Light Sweet
thousand barrels
thousand barrels of oil equivalent
thousand cubic feet
thousand cubic feet per day
million British Thermal Units
million British Thermal Units per day
million cubic feet
million cubic feet per day
natural gas liquids
New York Mercantile Exchange
New York Stock Exchange
Toronto Stock Exchange
Western Canadian Select
West Texas Intermediate
*
Oil equivalent amounts may be misleading, particularly if used in isolation. In accordance with NI 51-101, a boe conversion
ratio for natural gas of 6 Mcf: 1 bbl has been used, which is based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value equivalency at the wellhead.
Baytex Energy Corp. 2020 Annual Report
85
CORPORATE
INFORMATION
BOARD OF DIRECTORS
OFFICERS
Edward D. LaFehr
President and
Chief Executive Officer
Rodney D. Gray
Executive Vice President
and Chief Financial Officer
Brian G. Ector
Vice President, Capital Markets
Kendall D. Arthur
Vice President, Heavy Oil
Chad L. Kalmakoff
Vice President, Finance
Scott Lovett
Vice President,
Corporate Development
Chad E. Lundberg
Vice President, Light Oil
Mark R. Bly
Chair of the Board
Edward D. LaFehr
Director
Trudy M. Curran 2,4
Director
Naveen Dargan 1,3
Director
Don G. Hrap 2
,3
Director
Jennifer A. Maki 1,2
Director
Gregory K. Melchin 1,4
Director
David L. Pearce 3,4
Director
Steve D.L. Reynish 3,4
Director
(1) Member of the Audit Committee
(2) Member of the Human Resources
and Compensation Committee
(3) Member of the Reserves
and Sustainability Committee
(4) Member of the Nominating
and Governance Committee
HEAD OFFICE
Baytex Energy Corp.
Centennial Place, East Tower
2800, 520 - 3rd Avenue SW
Calgary, Alberta T2P 0R3
Toll-free 1.800.524.5521
T 587.952.3000
F 587.952.3001
www.baytexenergy.com
Design: ARTHUR / HUNTER
Printing: Merrill Corporation
AUDITORS
KPMG LLP
BANKERS
Bank of Nova Scotia
ATB Financial
Bank of Montreal
Barclays Bank plc
Canadian Imperial Bank of Commerce
Caisse Centrale Desjardins
Export Development Canada
National Bank of Canada
Royal Bank of Canada
The Toronto-Dominion Bank
Wells Fargo Bank
RESERVES ENGINEERS
McDaniel & Associates Consultants Ltd.
TRANSFER AGENT
Odyssey Trust Company
EXCHANGE LISTING
Toronto Stock Exchange
Symbol: BTE
W W W. B AY T E X E N E R G Y. C O M