Committed to building a
BRIGHT
FUTURE
2 0 1 9
Annual Report
T S X B T E | N Y S E B T E
Our
Highlights
Our Operating
Areas
97,680 boe/d
for the full-year 2019
$1.01 billion
of EBITDA for the
full-year 2019
17%
reduction in net debt
($393 million) in 2019
Peace River
Duvernay
Lloydminster
Viking
112%
production replacement
from development activities
Eagle Ford
Table of Contents
5
Message
to Shareholders
7
Management’s
Discussion and
Analysis
44
Management’s
Report
45
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
Bank loan
(2)
Long-term notes
(2)
Long-term debt
Working capital deficiency
Net debt
(1)
Shares Outstanding - basic (thousands)
Weighted average
End of period
Years Ended
December 31,
2019
December 31,
2018
$
1,805,919 $
1,428,870
902,426
472,983
1.62
1.62
(12,459)
(0.02)
(0.02)
1.35
1.35
(325,309)
(0.93)
(0.93)
$
$
$
$
552,291 $
2,180
554,471 $
495,721
1,603,850
2,099,571
506,471 $
1,337,200
1,843,671
28,120
1,871,791 $
522,294
1,596,323
2,118,617
146,550
2,265,167
557,048
558,305
351,542
554,060
Baytex Energy Corp. 2019 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)
(3)
Netback (thousands of Canadian dollars)
Total sales, net of blending and other expense
(4)
Royalties
Operating expense
Transportation expense
Operating netback
General and administrative
Cash financing and interest
Realized financial derivatives gain (loss)
(5)
Other
Adjusted funds flow
(1)
Netback (per boe)
Total sales, net of blending and other expense
(4)
Royalties
Operating expense
Transportation expense
Operating netback
(1)
General and administrative
Cash financing and interest
Realized financial derivatives (loss) gain
(5)
Other
Adjusted funds flow
(1)
Notes:
Years Ended
December 31,
2019
December 31,
2018
43,587
26,741
10,229
80,557
102,742
97,680
29,264
25,954
9,745
64,963
92,971
80,458
1,737,124 $
1,360,038
(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 $
(313,754)
(311,592)
(36,869)
697,823
(45,825)
(104,318)
(73,165)
(1,532)
472,983
46.31
(10.68)
(10.61)
(1.26)
23.76
(1.56)
(3.55)
(2.49)
(0.05)
16.11
$
$
$
$
$
$
(1)
(2)
(3)
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.
Principal amount of instruments. The carrying amount of debt issue costs associated with the bank loan and long-term notes are excluded on the basis that
these amounts have been paid by Baytex and do not represent an additional source of capital or repayment obligations.
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.
(4) 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.
(5) Other is comprised of realized foreign exchange gain or loss, other income or expense, current income tax expense or recovery and payments on onerous
contracts. Refer to the 2019 MD&A for further information on these amounts.
2
Baytex Energy Corp. 2019 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 "anticipate", "believe", "continue", "could", "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 have flexibility to execute our business plan driving free cash flow and strengthening our balance sheet; our 2020 production
and capital expenditure guidance; that our exploration and development program is expended to be fully funded by adjusted funds
flow at the forward strip and we have flexibility to adjust our spending plans; the percentage of our net crude oil exposure that is
hedged for 2020; that after completing the announced redemption of long-term notes our credit facilities will be one-third undrawn, we
will have over $300 million of liquidity and the weighted average cost of our debt will be approximately 6%; that we have a strong
drilling inventory of approximately 10 or more years in each core asset; we are committed to stable production, generating free
cash flow and strengthening our balance sheet.
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; availability and cost of gathering, processing and pipeline systems; failure to comply with the covenants in our debt
agreements; the availability and cost of capital or borrowing; that our credit facilities may not provide sufficient liquidity or may not be
renewed; risks associated with a third-party operating our Eagle Ford properties; the cost of developing and operating our assets;
depletion of our reserves; risks associated with the exploitation of our properties and our ability to acquire reserves; 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; public perception and
its influence on the regulatory regime; restrictions or costs imposed by climate change initiatives; variations in interest rates and foreign
exchange rates; risks associated with our hedging activities; 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 associated with acquiring, developing and exploring for oil and natural gas and other aspects of our operations; risks
associated with large projects; 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; 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, 2019, to be filed with Canadian securities regulatory authorities and the
U.S. Securities and Exchange Commission not later than March 31, 2020 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. 2019 Annual Report
3
Non-GAAP Financial and Capital Management Measures
In this report, we refer to certain financial measures (such as adjusted funds flow, EBITDA, 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, EBITDA, 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, 2019.
EBITDA is not a measurement based on GAAP in Canada. EBITDA is defined as net income or loss adjusted for financing and interest
expenses, unrealized gains and losses on financial derivatives, income tax, non-recurring losses, payments on lease obligations,
certain specific unrealized and non-cash transactions (including depletion, exploration and evaluation expenses, unrealized gains and
losses on financial derivatives and foreign exchange and share-based compensation).
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 bank loan. 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 bank loan 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 bank loan 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. 2019 Annual Report
MESSAGE TO SHAREHOLDERS
While we have been a publicly listed corporation for more than 25 years, we are taking steps to systematically
transform Baytex. We are now a company with a diversified North American oil portfolio designed to generate free
cash flow. We have shifted our portfolio to predominantly high operating netback, light oil assets while also
reducing our cash cost structure and improving capital efficiencies. More recently, we have refinanced our long-
term notes and extended the term of our revolving credit facilities to 2024. These steps give us the confidence
and flexibility to execute our business plan to continue driving free cash flow and strengthening our balance sheet.
Despite the many challenges facing our industry today, we recognize that developing environmentally and socially
responsible energy plays an important role in raising the standard of living for people around the world. In 2019
we continued our excellent health, safety and environmental performance and published our fourth biennial
corporate sustainability report. This report demonstrates our commitment to transparency and to managing the
environmental and social impacts of our business. We have elevated our standards, establishing a target to
reduce our greenhouse gas emissions intensity by 30% over the next three years. We believe our safety and
environmental leadership will serve us well as we continue to adapt to changing market conditions.
We have a high quality and diversified oil portfolio and our operating teams are well established with a track
record of delivering results. 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 East Shale
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.
Our 2019 operating and financial results demonstrate the benefits of this diversified oil weighted portfolio and our
commitment to allocate capital effectively, generate free cash flow and further strengthen our balance sheet. We
produced 97,680 boe/d (82% liquids) and exceeded the high end of our annual guidance with capital expenditures
at the low end of guidance totaling $552 million. This resulted in the following financial results:
• EBITDA of $1 billion and free cash flow of $329 million.
• Net debt reduction of 17%, or $393 million, due to the strong free cash flow and a strengthening of the
Canadian dollar relative to the U.S. dollar.
• Redeemed our US$150 million principal amount of 6.75% senior unsecured notes nearly two years early.
We also demonstrated reserves growth with proved developed producing reserves increasing 5%, finding &
development costs of $13/boe and a recycle ratio of 2.3x. In aggregate, we replaced 112% of 2019 production,
adding 40 million boe of proved plus probable reserves through development activities. In the Eagle Ford, strong
well performance continues to be driven by enhanced completions across our acreage position. In the Viking,
over 90% of our drilling is now comprised of extended reach horizontal wells. In our heavy oil assets we delivered
stable production with limited capital investment. We also continued to advance our Duvernay shale light oil asset
with two strong wells in the East Shale Basin.
Subsequent to year-end, we issued US$500 million principal amount of 8.75% senior unsecured notes, maturing
on April 1, 2027 which enabled us to redeem two series of notes; US$400 million principal amount of 5.125%
senior unsecured notes due June 1, 2021 and $300 million principal amount of 6.625% senior unsecured notes
due July 19, 2022. Following the redemption of these notes, our next long-term note maturity is June 2024.
We also extended the maturities of our revolving credit facilities and term loan to April 2, 2024. These credit
facilities, which total $1.046 billion, are not borrowing base facilities and do not require annual or semi-annual
reviews. Following all of these steps, our credit facilities are approximately one-third undrawn and we retain over
$300 million of liquidity with a weighted average interest rate on our long-term debt of approximately 6%.
Baytex Energy Corp. 2019 Annual Report
5
Looking Forward
We maintain an attractive and deep inventory of development locations with approximately ten years or more of
remaining drilling opportunities in each of our core assets. We remain committed to delivering stable
production, maximizing free cash flow and further strengthening our balance sheet.
Our 2020 annual guidance is unchanged as we target production of 93,000 to 97,000 boe/d with exploration and
development expenditures of $500 to $575 million. At the time of writing, our exploration and development
program is expected to be fully funded from adjusted funds flow at the forward strip and we have the operational
flexibility to adjust our spending plans based on changes in commodity prices.
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 2020, 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$58/bbl with upside participation to US$63/bbl. We are also contracted to
deliver 11,500 bbl/d of our heavy oil volumes to market by rail.
Baytex’s success is due to very engaged Board, management and employee group who are all strongly aligned
and committed to driving value for shareholders. With the combined team, we are confident we have the skills,
experience and focus that will create a more prosperous future.
We look forward to executing our plans in 2020 for the ongoing benefit of all stakeholders and we thank you for
your continued support.
Sincerely,
Edward D. LaFehr
President and Chief Executive Officer
March 4, 2020
6
Baytex Energy Corp. 2019 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, 2019 and 2018. This information is provided as of March 3, 2020. 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, 2019
("Q4/2019" and "2019") have been compared with the results for the three months and year ended December 31, 2018 ("Q4/2018"
and "2018"). 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, 2019 and 2018, together with the accompanying notes and
the Annual Information Form for the year ended December 31, 2019. 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 the 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. 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.
STRATEGIC COMBINATION
On August 22, 2018, Baytex and Raging River Exploration Inc. ("Raging River") completed the strategic combination of the two
companies (the "Strategic Combination") by way of a plan of arrangement whereby Baytex acquired all of the issued and
outstanding common shares of Raging River. The Strategic Combination increased our light oil exposure and operational control of
our properties while improving our leverage ratios. Production from Raging River's properties is approximately 90% light oil from
the Viking and Duvernay. The addition of the primarily operated assets to our portfolio increased our inventory of drilling prospects
and increased our ability to effectively allocate capital. Our comparative 2018 results include the results from Raging River from the
closing date August 22, 2018.
2019 ANNUAL HIGHLIGHTS
Baytex delivered solid operating and financial results for 2019. Production of 97,680 boe/d for 2019 exceeded the top end of our
2019 annual guidance while exploration and development expenditures of $552.3 million were at the low end of guidance. Strong
well performance along with the disciplined execution of our exploration and development program resulted in free cash flow of
$328.8 million for 2019 which contributed to a $393.4 million decrease in net debt.
In Canada, production of 58,625 boe/d for 2019 was 15,243 boe/d higher than 43,382 boe/d in 2018 which reflects the impact of
the Strategic Combination along with our exploration and development program. Exploration and development expenditures of
$374.4 million were focused on our Viking light oil property along with additional heavy oil development at Peace River and
Lloydminster. Exploration and development expenditures included costs associated with drilling 279 (247.8 net) light oil wells in the
Viking and Duvernay along with 42 (42.0 net) heavy oil wells during 2019.
In the U.S., strong well performance from wells brought on stream during 2019 contributed to production of 39,055 boe/d which
was 1,980 boe/d higher than 37,076 boe/d for 2018 despite relatively consistent completion activity in both periods. We invested
$177.9 million on exploration and development activity during 2019 and drilled 96 (20.2 net) wells and commenced production from
Baytex Energy Corp. 2019 Annual Report
7
109 (25.1 net) wells. During 2018 we drilled 91 (20.8 net) wells and commenced production from 120 (26.2 net) wells on our Eagle
Ford properties.
In 2019, we benefited from narrower Canadian light and heavy oil differentials after production curtailments mandated by the
Government of Alberta came into effect in January 2019. The Edmonton par light oil benchmark averaged $69.22/bbl in 2019 which
represents a differential of US$4.86/bbl to the West Texas Intermediate ("WTI") benchmark price as compared to a US$11.30/bbl
in Q4/2018. The Western Canadian Select ("WCS") heavy oil differential
differential
averaged US$12.75/bbl in 2019 relative to a differential of US$26.31/bbl in 2018 and a differential of US$39.42/bbl in Q4/2018.
Stronger Canadian oil differentials helped to mitigate the impact of a lower WTI benchmark price which was US$57.03/bbl in 2019
compared to US$64.77/bbl during 2018.
in 2018 and a US$26.51/bbl differential
We generated adjusted funds flow of $902.4 million in 2019 which was $429.4 million higher than $473.0 million for 2018. The
increase is primarily due to a $277.4 million increase in operating netback driven by increased production from the Strategic
Combination, strong well performance from our development program and tighter oil differentials on our Canadian production.
Realized gains on financial derivatives of $75.6 million in 2019 also contributed to the increase in adjusted funds flow relative to
2018 when we recorded realized losses on financial derivatives of $73.2 million. The $429.4 million increase in adjusted funds flow
contributed to the $312.9 million decrease in our net loss to $12.5 million for 2019 compared to a net loss of $325.3 million in 2018.
In 2019, we recorded impairments of $187.8 million due to a sustained decline in Canadian heavy oil prices which resulted in a
change in development plans for our thermal projects at Peace River compared to total impairments of $285.3 million in 2018
related to our Conventional and Eagle Ford assets.
Free cash flow of $328.8 million for 2019 reflects our strong operational and financial results along with the disciplined execution of
our exploration and development program. Free cash flow generated in 2019 contributed to a $393.4 million decrease in net debt to
$1,871.8 million at December 31, 2019, as compared to $2,265.2 million at December 31, 2018. Net debt also decreased due to a
strengthening of the Canadian dollar at December 31, 2019 which reduced the reported amount of our U.S. dollar denominated net
debt by $62.8 million relative to December 31, 2018.
2020 SENIOR NOTE FINANCING
On February 5, 2020, we issued US$500 million of senior unsecured notes bearing interest at 8.75% payable semi-annually which
mature on April 1, 2027 (the "8.75% Senior Notes"). These 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.
On February 20, 2020, we used a portion of the net proceeds from the issuance of the 8.75% Senior Notes to redeem our US$400
million principal amount of our 5.125% senior unsecured notes due June 1, 2021 at par plus accrued interest. We also issued a
redemption notice for the $300 million principal amount of our 6.625% senior unsecured notes due July 19, 2022 for early
redemption on March 6, 2020 at 101.104% of the principal amount plus accrued interest. After completing the early redemption of
the 6.625% senior unsecured notes our next unsecured debt maturity is June 1, 2024 when the US$400 million principal amount of
5.625% notes are due.
8
Baytex Energy Corp. 2019 Annual Report
GUIDANCE
The following table compares our 2019 annual guidance compared to our 2019 results.
Exploration and development expenditures ($ millions)
Production (boe/d)
Expenses:
Royalty rate (%)
Operating ($/boe)
Transportation ($/boe)
Original guidance (1)
$550 - $650
93,000 - 97,000
20.0
$10.75 - $11.25
$1.25 - $1.35
2019
$552.3
97,680
18.4
$11.16
$1.23
General and administrative ($ millions)
Cash interest ($ millions)
~ $46 ($1.30/boe)
$45.5 ($1.28/boe)
~ $112 ($3.23/boe)
$107.4 ($3.01/boe)
(1) As announced on December 17, 2018. Includes updated guidance on May 2, 2019 for general and administrative expenses to reflect a
change associated with the adoption of IFRS 16.
On December 4, 2019 our Board of Directors approved our 2020 capital budget of $500 - $575 million which is designed to
generate production of 93,000 - 97,000 boe/d. The program is expected to be equally weighted between the first and second half
of 2020 and we will maintain operational flexibility to adjust spending in response to commodity prices.
The following table summarizes our 2020 guidance as released on December 4, 2019.
Exploration and development expenditures ($ millions)
Production (boe/d)
Expenses:
Royalty rate (%)
Operating ($/boe)
Transportation ($/boe)
General and administrative ($ millions)
Cash interest ($ millions)
Leasing expenditures ($ millions)
Asset retirement obligations ($ millions)
2020 Guidance
$500 - $575 million
93,000 - 97,000
18.0 - 18.5
$11.25 - $12.00
$1.20 - $1.30
$45 ($1.30/boe)
$112 ($3.23/boe)
$7
$19
Baytex Energy Corp. 2019 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
Light oil and condensate
Heavy oil
NGL
Natural gas
Years Ended December 31
2019
2018
Canada
U.S.
Total
Canada
U.S.
Total
22,358
26,741
1,364
50,463
48,969
58,625
38 %
46 %
2 %
14 %
21,229
—
8,865
30,094
53,773
39,055
54 %
— %
23 %
23 %
43,587
26,741
10,229
80,557
102,742
97,680
45 %
27 %
10 %
18 %
8,959
25,954
1,199
36,112
43,622
43,382
21 %
60 %
3 %
16 %
20,305
—
8,546
28,851
49,349
37,076
55 %
— %
23 %
22 %
29,264
25,954
9,745
64,963
92,971
80,458
37 %
32 %
12 %
19 %
Strong operational performance in 2019 resulted in production of 97,680 boe/d which exceeded the high end of our annual
production guidance of 93,000 to 97,000 boe/d. Production for 2019 was 17,222 boe/d higher than 80,458 boe/d in 2018 due to the
Strategic Combination along with production related to our exploration and development program.
In Canada, production of 58,625 boe/d in 2019 was up 35% from 43,382 boe/d in 2018. The increase in production in 2019 relative
to 2018 is primarily due to the Strategic Combination along with strong well performance from our exploration and development
program. Production from our Viking and Duvernay properties consists of approximately 90% light oil which resulted in a higher
proportion of our Canadian production being comprised of light oil in 2019 compared to 2018.
U.S. production averaged 39,055 boe/d in 2019 which is up 5% from 37,076 boe/d for 2018. We experienced strong production
results from wells brought on stream in 2019 which resulted a 1,980 boe/d increase in production compared to 2018 despite
consistent completion activity in both periods. During 2019 we commenced production from 109 (25.1 net) wells compared to 120
(26.2 net) wells during 2018.
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 lower in 2019 as forecasted demand levels were impacted by the ongoing trade dispute
between the U.S. and China which more than offset the effect of compliance with OPEC production curtailments along with U.S.
imposed sanctions on Iran and Venezuela. North American benchmark prices for 2019 were lower than 2018 as a result of
increasing supply from U.S. production along with uncertainty around future global demand for crude oil. Canadian oil differentials
were tighter in 2019 compared to 2018 due to the Government of Alberta's production curtailments which came into effect in
January of 2019. While our 2019 production levels were not significantly impacted by the Government of Alberta's curtailment
program we benefited from narrower differentials for our Canadian light and heavy oil production in 2019.
We compare the price received for our U.S. crude oil production to the Louisiana Light Sweet ("LLS") stream at St. James,
Louisiana, which is a representative benchmark for light oil pricing at the U.S. Gulf Coast. During 2019, the LLS benchmark
averaged US$62.84/bbl representing a premium of US$5.81/bbl relative to WTI, compared to an LLS price of US$70.09/bbl or a
premium of US$5.32/bbl to WTI for 2018.
10
Baytex Energy Corp. 2019 Annual Report
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 $69.22/bbl for 2019
which is consistent with $69.31/bbl for 2018 despite the decline in WTI pricing over the same periods as differentials were tighter in
2019. Edmonton par traded at a US$4.86/bbl discount to WTI in 2019 compared to a US$11.30/bbl discount for 2018.
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. With curtailments, we benefited from a narrower WCS heavy oil
differential in 2019 which averaged US$12.75/bbl in 2019 as compared to US$26.31/bbl for 2018. As a result, the WCS heavy oil
benchmark price of $58.75/bbl increased $8.90/bbl from $49.85/bbl in 2018 despite a $8.28/bbl decrease in WTI (expressed in
Canadian dollars) over the same periods.
Natural Gas
U.S. natural gas prices for 2019 were lower than 2018 as U.S. natural gas production has outpaced growth in natural gas demand.
Canadian natural gas prices remained challenged during 2019 as a lack of egress from Western Canada continues to impact
natural gas prices in the region.
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$2.63/mmbtu in 2019 which is lower than US$3.09/mmbtu in 2018. Record natural
gas production levels in the U.S. have resulted in an oversupplied North American market and lower natural gas prices in 2019
relative to 2018.
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 increasing supply and limited market access for Canadian natural gas production. The AECO benchmark averaged $1.62/
mcf during 2019 which is $0.08/mcf higher than the benchmark average of $1.54/mcf during 2018.
Benchmark Averages
WTI oil (US$/bbl)(1)
LLS oil (US$/bbl)(2)
LLS oil differential to WTI (US$/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
Years Ended December 31
2019
57.03
62.84
5.81
69.22
(4.86)
58.75
(12.75)
1.62
2.63
1.3269
2018
Change
64.77
70.09
5.32
69.31
(11.30)
49.85
(26.31)
1.54
3.09
1.2962
(7.74)
(7.25)
0.49
(0.09)
6.44
8.90
13.56
0.08
(0.46)
0.0307
(1) WTI refers to the arithmetic average of NYMEX prompt month WTI for the applicable period.
(2) LLS refers to the Argus trade month average for Louisiana Light Sweet oil.
(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.
Baytex Energy Corp. 2019 Annual Report
11
Average Realized Sales Prices(1)
Light oil and condensate ($/bbl)
Heavy oil ($/bbl)(2)
NGL ($/bbl)
Natural gas ($/mcf)
Weighted average ($/boe)(2)
Years Ended December 31
2019
2018
Canada
U.S.
Total
Canada
U.S.
Total
$
65.99 $
77.46 $
71.57 $
51.78 $
85.96 $
44.20
16.93
1.71
—
18.74
3.43
44.20
18.50
2.61
36.20
33.21
1.48
—
31.10
4.20
$
47.15 $
51.08 $
48.72 $
34.76 $
59.83 $
75.50
36.20
31.36
2.92
46.31
(1) Baytex's risk management strategy employs both oil and natural gas financial and physical forward contracts (fixed price forward sales and
collars) and heavy oil differential physical delivery contracts (fixed price and percentage of WTI). The pricing information in this table excludes
the impact of financial derivatives.
(2) 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 $48.72/boe for 2019 which is up $2.41/boe from $46.31/boe for 2018. Our realized price in
the U.S. was $51.08/boe in 2019 which is $8.75/boe lower than $59.83/boe in 2018 due to the decrease in U.S. crude oil
benchmark prices. In Canada, our realized price of $47.15/boe for 2019 was $12.39/boe higher than $34.76/boe for 2018.
Canadian realized prices increased as narrower differentials improved heavy and light oil prices which more than offset the impact
of a lower WTI price and we had a higher proportion of light oil from the Strategic Combination.
We compare our light oil realized price in Canada to the Edmonton par benchmark price. Our realized light oil and condensate
price in 2019 was $65.99/bbl representing a discount of $3.23/bbl to the Edmonton par benchmark compared to 2018 when our
realized price was $51.78/bbl or a discount of $17.53/bbl. The majority of our 2018 light oil production occurred after closing of the
Strategic Combination and was impacted by a sharp widening of Canadian oil differentials in Q4/2018 which resulted in a wider
discount to the Edmonton par benchmark reported for the annual period. The discount of $3.23/bbl for 2019 is relatively consistent
with our realized Q4/2018 discount of $2.14/bbl to Edmonton par.
We compare the price received for our U.S. light oil and condensate production to the LLS benchmark. Our realized light oil and
condensate price averaged $77.46/bbl for 2019 compared to $85.96/bbl for 2018. Expressed in U.S. dollars, our realized light oil
and condensate price of US$58.38/bbl for 2019 reflects a US$4.46/bbl discount to the LLS benchmark for 2019 compared to a
discount of US$3.77/bbl in 2018. In 2019, our price realizations relative to LLS was impacted by a change in certain marketing
contracts to be priced on the Magellan East Houston ("MEH") benchmark which represents light oil pricing at the Magellan East
crude oil terminal in Houston, Texas. In 2020, we expect to compare our realized light oil price to the MEH benchmark as the
majority of our light oil and condensate contracts are now referenced to the MEH benchmark price.
Our realized heavy oil price, net of blending and other expense averaged $44.20/bbl in 2019 compared to $36.20/bbl in 2018. The
$8.00/bbl increase in our realized heavy oil price for 2019 is fairly consistent with the $8.90/bbl increase in the WCS benchmark
from 2018. Our realized heavy oil price did not increase as much as the WCS benchmark due to certain WTI based heavy oil rail
contracts that were entered into prior to the Government of Alberta's decision to curtail production which resulted in a narrowing of
the WCS differential.
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 $18.50/bbl in 2019 or 24% of WTI (expressed
in Canadian dollars) compared to $31.36/bbl or 37% of WTI (expressed in Canadian dollars) in 2018. The decrease in our NGL
price for 2019 is consistent with the increase in the production and supply of NGLs in North America which resulted in lower market
prices for propane and butane relative to 2018.
We compare our realized natural gas price in Canada to the AECO benchmark price. Our realized natural gas price for 2019 was
$1.71/mcf compared to $1.48/mcf in 2018. The $0.23/mcf increase in our realized natural gas price in 2019 is higher than the
$0.08/mcf increase in the AECO natural gas price over the same period as the natural gas in our Viking asset acquired in the
Strategic Combination received higher natural gas pricing relative to our legacy Baytex properties in Canada. In the U.S., our
realized natural gas price was US$2.58/mmbtu for 2019 compared to US$3.24/mmbtu in 2018. Our realized natural gas price in the
U.S. is relatively consistent with the NYMEX benchmark in 2019 and 2018.
12
Baytex Energy Corp. 2019 Annual Report
Petroleum and Natural Gas Sales
($ thousands)
Oil sales
Light oil and condensate
Heavy oil
NGL
Total liquids sales
Natural gas sales
Total petroleum and natural gas sales
Blending and other expense
Total sales, net of blending and other expense
Years Ended December 31
2019
2018
Canada
U.S.
Total
Canada
U.S.
Total
$
538,487 $
500,187
8,430
1,047,104
30,620
1,077,724
(68,795)
$ 1,008,929 $
600,163 $ 1,138,650 $
—
60,647
660,810
67,385
728,195
—
500,187
69,077
1,707,914
98,005
1,805,919
(68,795)
728,195 $ 1,737,124 $
169,335 $
411,794
14,531
595,660
23,555
619,215
(68,832)
550,383 $
637,055 $
—
97,008
734,063
75,592
809,655
—
806,390
411,794
111,539
1,329,723
99,147
1,428,870
(68,832)
809,655 $ 1,360,038
Total sales, net of blending and other expense, of $1,737.1 million for 2019 increased $377.1 million from $1,360.0 million reported
for 2018. Total sales, net of blending and other expense, was higher in 2019 due to production from the Strategic Combination
along with strong operational results from our exploration and development program and from a $2.41/boe increase in our weighted
average realized price compared to 2018.
In Canada, total sales, net of blending and other expense, was $1,008.9 million for 2019 which is an increase of $458.5 million from
$550.4 million reported for 2018. Total petroleum and natural gas sales increased with production from the Strategic Combination
and our exploration and development program. The 15,243 boe/d increase in production for 2019 resulted in a $193.4 million
increase in total sales, net of blending and other expense, relative to 2018. Our average realized price for 2019 was $12.39/boe
higher than 2018 as a result of stronger heavy and light oil and condensate price realizations from narrower oil differentials. The
increase in our realized price in 2019 resulted in a $265.1 million increase in total sales, net of blending and other expense, relative
to 2018.
In the U.S., petroleum and natural gas sales were $728.2 million for 2019 which is a decrease of $81.5 million from $809.7 million
reported for 2018. Our realized price for 2019 was $8.75/boe lower due to the decline in U.S. benchmark prices and resulted in a
$124.7 million decrease in total petroleum and natural gas sales relative to 2018. The decrease in total sales due to lower realized
pricing was partially offset by a 1,979 boe/d increase in production in 2019 which resulted in a $43.2 million increase in total sales
compared to 2018.
Royalties
Royalties are paid to various government entities and to land and mineral rights owners. Royalties are calculated based on gross
revenues or on operating netbacks less capital
investment for specific heavy oil projects, and are generally expressed as a
percentage of total sales, net of blending and other expense. The actual royalty rates can vary for a number of reasons, including
the commodity produced, royalty contract terms, commodity price level, royalty incentives and the area or jurisdiction.
Years Ended December 31
2019
2018
($ thousands except for % and per boe)
Canada
U.S.
Total
Canada
U.S.
Total
Royalties
Average royalty rate(1)
Royalty rate per boe
$
107,467 $
212,774 $
320,241 $
72,700 $
241,054 $
313,754
10.7 %
29.2 %
18.4 %
13.2 %
29.8 %
23.1 %
$
5.02 $
14.93 $
8.98 $
4.59 $
17.81 $
10.68
(1) Average royalty rate is calculated as royalties divided by total sales, net of blending and other expense.
Total royalties for 2019 were $320.2 million or 18.4% of total sales, net of blending and other expense, compared to $313.8 million
or 23.1% in 2018. Our average royalty rate of 18.4% for 2019 is below our annual guidance of approximately 20.0% and decreased
from 2018 mainly due to the Strategic Combination.
In Canada, total royalties were $107.5 million or 10.7% of sales, net of blending and other expense, for 2019 compared to $72.7
million or 13.2% of sales, net of blending and other expense, in 2018. Our overall royalty rate in Canada decreased following the
Strategic Combination due to the lower royalty rate on our Viking and Duvernay properties as compared to our heavy oil properties.
Total royalties of $107.5 million in 2019 were higher than $72.7 million in 2018 due to the increase in total sales, net of blending
and other expense.
Baytex Energy Corp. 2019 Annual Report
13
Total royalties in the U.S. were $212.8 million or 29.2% of sales for 2019 compared to $241.1 million or 29.8% of sales reported for
2018. The royalty rate on our U.S. production does not vary with price but can vary across our acreage. Royalties for 2019
averaged 29.2% of petroleum and natural gas sales which is consistent with 29.8% for 2018. The decrease in total royalties in
2019 compared to 2018 is consistent with the decrease in total petroleum and natural gas sales over the same period.
Operating Expense
Years Ended December 31
2019
2018
($ thousands except for per boe)
Operating expense
Operating expense per boe
Canada
U.S.
Total
Canada
U.S.
Total
298,303 $
99,413 $
397,716 $
221,717 $
89,875 $
311,592
13.94 $
6.97 $
11.16 $
14.00 $
6.64 $
10.61
$
$
Operating expense was $397.7 million ($11.16/boe) in 2019 compared to $311.6 million ($10.61/boe) for 2018. The increase in total
operating expense can be attributed to higher production in 2019 along with an increase in the proportion of our annual production
from Canada relative to 2018. Operating expense of $11.16/boe for 2019 is consistent with expectations and is within our 2019
annual guidance range of $10.75 - $11.25/boe.
In Canada, operating expense was $298.3 million ($13.94/boe) for 2019 compared to $221.7 million ($14.00/boe) for 2018. The
increase in total operating expense in Canada is a result of the additional production from the Strategic Combination as our per unit
operating expense of $13.94/boe is consistent with $14.00/boe in 2018. U.S. operating expense was $99.4 million ($6.97/boe) for
2019 compared to $89.9 million ($6.64/boe) for 2018. The increase in total operating expense reflects higher U.S. production
combined with a weaker Canadian dollar during 2019 compared to 2018. Expressed in U.S. dollars, per boe operating expense of
US$5.25/boe in 2019 is consistent with US$5.12/boe in 2018.
Transportation Expense
Transportation expense includes the costs to move production from the field to the sales point. The largest component of
transportation expense relates to the trucking of oil in Canada to pipeline and rail terminals which can vary from period to period
depending on hauling distances as we seek to optimize sales prices and trucking rates.
($ thousands except for per boe)
Transportation expense
Transportation expense per boe
Canada
43,942 $
2.05 $
$
$
U.S.
Total
Canada
— $
— $
43,942 $
36,869 $
1.23 $
2.33 $
U.S.
— $
— $
Total
36,869
1.26
Years Ended December 31
2019
2018
We reported transportation expense of $1.23/boe for 2019 which is slightly below our annual guidance range of $1.25 - $1.35/boe
for 2019. Transportation expense was $43.9 million ($1.23/boe) for 2019 was higher than $36.9 million ($1.26/boe) for 2018 and
reflects additional oil trucking and transportation costs associated with our Viking and Duvernay light oil properties acquired as part
of the Strategic Combination.
Blending and Other Expense
Blending and other expense primarily includes the cost of blending diluent purchased in order to reduce the viscosity of our heavy
oil transported through pipelines to meet pipeline specifications. The purchased diluent is recorded as blending and other expense.
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. Accordingly, our heavy oil sales price
realization can fluctuate depending on the quantity and price of blending diluent required to meet pipeline specifications.
Blending and other expense was $68.8 million for 2019 and 2018 as total blending volumes and prices were relatively consistent in
both periods.
14
Baytex Energy Corp. 2019 Annual Report
Financial Derivatives
As part of our normal operations, we are exposed to movements in commodity prices, foreign exchange rates and interest rates. In
an effort to manage these exposures, we utilize various financial derivative contracts which are intended to partially reduce the
volatility in our adjusted funds flow. Contracts settled in the period result in realized gains or losses based on the market price
compared to the contract price and the notional volume outstanding. Changes in the fair value of unsettled contracts are reported
as unrealized gains or losses in the period as the forward markets for commodities and currencies fluctuate and as new contracts
are executed.
($ 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
Total
Total financial derivatives gain (loss)
Crude oil
Natural gas
Interest and financing
Total
Years Ended December 31
2019
2018
Change
72,052 $
3,577
(9)
75,620
(80,602)
(1,857)
(358)
(82,817)
(8,550)
1,720
(367)
(7,197) $
(74,902) $
1,765
(28)
(73,165)
117,087
(697)
325
116,715
42,185
1,068
297
43,550 $
146,954
1,812
19
148,785
(197,689)
(1,160)
(683)
(199,532)
(50,735)
652
(664)
(50,747)
$
$
We recorded a total financial derivatives loss of $7.2 million for 2019. Realized financial derivatives gains of $75.6 million for 2019
were 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 $82.8 million for 2019 reflects the realization of our net financial derivatives asset recorded at
December 31, 2018 along with changes in the fair value of our contracts entered for 2020.
Realized gains on crude oil financial derivatives of $72.1 million in 2019 are a result of market prices for Brent and WTI settling at
levels below the prices set in our contracts outstanding during the period. Our natural gas financial derivatives generated gains of
$3.6 million and were a result of the NYMEX index averaging less that the fixed price on our NYMEX contracts in place for 2019.
Unrealized losses of $82.8 million recorded for 2019 reflects the decrease in the fair value of our net unrealized financial
derivatives position from December 31, 2018. At December 31, 2018, our net asset of $79.6 million was primarily associated with
contracts for 2019 which generated realized gains of $75.6 million during 2019. The unrealized loss for 2019 also reflects changes
in value for our 2020 financial derivative contracts which resulted in a net liability of $3.2 million at December 31, 2019.
Baytex Energy Corp. 2019 Annual Report
15
We had the following commodity financial derivative contracts as at March 3, 2020.
Remaining Period
Volume
Price/Unit (1)
Jan 2020 to Dec 2020
Apr 2020 to Dec 2020
Jan 2020 to Dec 2020
Apr 2020 to Dec 2020
Jan 2020 to Mar 2020
Jan 2020 to Dec 2020
Jan 2020 to Dec 2020
Jan 2020 to Dec 2020
Jan 2020 to Dec 2020
Jan 2020 to Dec 2020
Jan 2020 to Dec 2020
Jan 2020 to Dec 2020
Jan 2020 to Dec 2020
Jan 2020 to Dec 2020
Jan 2020 to Dec 2020
Jan 2020 to Dec 2020
Jan 2020 to Dec 2020
Jan 2020 to Dec 2020
Jan 2020 to Dec 2020
Jan 2021 to Dec 2021
Jan 2021 to Dec 2021
Jan 2021 to Dec 2021
2,500 bbl/d
4,000 bbl/d
2,000 bbl/d
3,000 bbl/d
6,000 bbl/d
2,000 bbl/d
3,000 bbl/d
3,000 bbl/d
4,500 bbl/d
3,000 bbl/d
1,000 bbl/d
1,000 bbl/d
1,500 bbl/d
1,500 bbl/d
1,000 bbl/d
1,000 bbl/d
1,000 bbl/d
1,000 bbl/d
2,000 bbl/d
3,000 bbl/d
3,000 bbl/d
3,000 bbl/d
WTI less US$16.10/bbl
WTI less US$16.38/bbl
WTI less US$6.50/bbl
WTI less US$5.92/bbl
US$56.60/bbl
US$58.00/bbl
US$50.00/US$56.00/US$61.35
US$50.00/US$57.00/US$60.00
US$50.00/US$57.00/US$62.00
US$50.00/US$58.00/US$62.00
US$51.00/US$58.00/US$60.50
US$51.00/US$58.00/US$60.83
US$51.00/US$59.00/US$65.60
US$51.00/US$59.00/US$66.00
US$51.00/US$59.50/US$66.15
US$51.00/US$60.00/US$65.60
US$51.00/US$60.00/US$66.00
US$51.00/US$60.00/US$66.05
US$51.00/US$60.00/US$66.70
US$64.50/bbl
US$70.00/bbl
US$60.75/bbl
Index
WCS
WCS
MSW
MSW
WTI
WTI
WTI
WTI
WTI
WTI
WTI
WTI
WTI
WTI
WTI
WTI
WTI
WTI
WTI
Brent
Brent
WTI
Oil
Basis swap
Basis swap (6)
Basis swap
Basis swap (6)
Fixed - Sell
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)
3-way option (2)
3-way option (2)
3-way option (2)
3-way option (2)
3-way option (2)
3-way option (2)
3-way option (2)
Swaption (3)
Swaption (4)
Swaption (4)
Natural Gas
3-way option (2)
Swaption (5)
Jan 2020 to Dec 2020
Jan 2021 to Dec 2021
5,000 mmbtu/d
5,000 mmbtu/d
US$2.25/US$2.60/US$2.85
US$2.90/mmbtu
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$50.00/US$58.00/US$62.00 contract, Baytex
receives WTI plus US$8.00/bbl when WTI is at or below US$50.00/bbl; Baytex receives US$58.00/bbl when WTI is between US$50.00/bbl and
US$58.00/bbl; Baytex receives the market price when WTI is between US$58.00/bbl and US$62.00/bbl; and Baytex receives US$62.00/bbl
when WTI is above US$62.00/bbl.
(3) For these contracts, the counterparty has the right, if exercised on September 30, 2020, to enter a swap transaction for the remaining term,
notional volume and fixed price per unit indicated above.
(4) For these contracts, the counterparty has the right, if exercised on December 31, 2020, to enter a swap transaction for the remaining term,
notional volume and fixed price per unit indicated above.
(5) For these contracts, the counterparty has the right, if exercised on December 23, 2020, to enter a swap transaction for the remaining term,
notional volume and fixed price per unit indicated above.
(6) Contracts entered subsequent to December 31, 2019.
Operating Netback
($ per boe except for volume)
Total production (boe/d)
Operating netback:
Years Ended December 31
2019
2018
Canada
58,625
U.S.
Total
39,055
97,680
Canada
43,382
U.S.
Total
37,076
80,458
Total sales, net of blending and other expense
$
47.15 $
51.08 $
48.72 $
34.76 $
59.83 $
46.31
Royalties
Operating expense
Transportation expense
Operating netback
Realized financial derivatives gain (loss)
Operating netback after financial derivatives
16
Baytex Energy Corp. 2019 Annual Report
(5.02)
(13.94)
(2.05)
(14.93)
(6.97)
—
(8.98)
(11.16)
(1.23)
(4.59)
(14.00)
(2.33)
(17.81)
(6.64)
—
$
$
26.14 $
29.18 $
27.35 $
13.84 $
35.38 $
—
—
2.12
—
—
26.14 $
29.18 $
29.47 $
13.84 $
35.38 $
(10.68)
(10.61)
(1.26)
23.76
(2.49)
21.27
Operating netback after financial derivatives of $29.47/boe increased $8.20/boe from $21.27/boe for 2018. Operating netback of
$27.35/boe for 2019 was $3.59/boe higher than $23.76/boe for 2018 due to stronger realized pricing as a result of narrower light
and heavy oil differentials relative to 2018. We recorded realized gains on financial derivatives of $2.12/boe in 2019 which resulted
in a $4.61/boe increase in operating netback after financial derivatives compared to 2018 when we recorded losses of $2.49/boe.
In Canada, our operating netback was $26.14/boe in 2019 compared to $13.84/boe in 2018. The increase in our operating netback
in Canada was driven by stronger realized pricing due the increase in light oil production following the Strategic Combination along
with narrower Canadian oil differentials in 2019 relative to 2018. Our operating netback in the U.S. of $29.18/boe in 2019 was lower
than $35.38/boe in 2018 due to the impact of lower U.S. benchmark prices on our realized sales price.
General and Administrative Expense
General and administrative ("G&A") expense includes head office and corporate costs such as salaries and employee benefits,
public company costs and administrative recoveries earned for operating capital and production activities on behalf of our working
interest partners. G&A expense fluctuates with head office staffing levels and the level of operated capital and production activity
during the period.
($ 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
2019
2018
51,660 $
56,318 $
(6,191)
(10,493)
45,469 $
45,825 $
1.28 $
1.56 $
Change
(4,658)
4,302
(356)
(0.28)
$
$
$
We reported G&A expense of $45.5 million ($1.28/boe) compared to $45.8 million ($1.56/boe) for 2018. G&A expense for 2019 was
in line with expectations and our annual guidance of approximately $46 million ($1.30/boe).
G&A expense of $45.5 million ($1.28/boe) for 2019 is slightly lower than $45.8 million ($1.56/boe) for 2018 which only includes the
additional staff and costs associated with the Strategic Combination following closing on August 22, 2018. In 2019 we continued to
optimize our business following integration of the two companies which resulted in a decrease in G&A expense per boe in 2019
relative to 2018 and reflects the efficiencies we were able to realize by combining the two organizations. A $4.1 million decrease in
rent expense in 2019 relative to 2018 was primarily due to the change in the accounting for leases which resulted in a change to
the presentation of payments for office leases.
Financing and Interest Expense
Financing and interest expense includes interest on our bank loan, long-term notes and lease obligations as well as non-cash
financing costs and the accretion on our asset retirement obligations. Financing and interest expense varies depending on debt
levels outstanding during the period and the applicable borrowing rates, CAD/USD foreign exchange rates, along with the carrying
amount of asset retirement obligations and the discount rates used to present value these obligations.
($ thousands except for per boe)
Interest on bank loan
Interest on long-term notes
Interest on lease obligations
Cash financing and interest expense
Accretion of debt issue costs
Accretion of asset retirement obligation
Financing and interest expense
Cash interest per boe
Financing and interest expense per boe
Years Ended December 31
2019
2018
$
20,376 $
15,637 $
86,431
610
88,681
—
107,417
104,318
4,735
13,713
3,854
10,914
$
$
$
125,865 $
119,086 $
3.01 $
3.53 $
3.55 $
4.06 $
Change
4,739
(2,250)
610
3,099
881
2,799
6,779
(0.54)
(0.53)
Baytex Energy Corp. 2019 Annual Report
17
We reported financing and interest expense of $125.9 million ($3.53/boe) for 2019 compared to $119.1 million ($4.06/boe) for 2018.
Cash interest expense of $107.4 million ($3.01/boe) for 2019 was below our 2019 annual guidance of approximately $112 million
($3.23/boe). We allocated our free cash flow to debt reduction and redeemed the US$150 million principal amount of 6.75% senior
unsecured notes in September of 2019 and reduced borrowings on our credit facilities throughout 2019 which resulted in lower
cash interest expense relative to our annual guidance.
Financing and interest expense was $125.9 million for 2019 which is $6.8 million higher than $119.1 million reported for 2018.
Interest on our bank loan of $20.4 million in 2019 increased $4.7 million relative to $15.6 million in 2018 due to the increase in loan
balances following the assumption of net debt associated with the Strategic Combination. The weighted average interest rate on
the credit facilities for 2019 was 4.0% as compared to 4.3% for 2018. We redeemed the US$150 million principal amount of 6.75%
senior unsecured notes on September 13, 2019 which resulted in lower interest on our long-term notes in 2019 compared to 2018.
Total accretion was higher in 2019 as our asset retirement obligation increased with the Strategic Combination.
Exploration and Evaluation Expense
Exploration and evaluation ("E&E") expense is related to the expiry of leases and the derecognition of costs for exploration
programs that have not demonstrated commercial viability and technical feasibility. E&E expense will vary depending on the timing
of lease expiries, the accumulated costs of expiring leases, and the economic facts and circumstances related to the Company's
exploration programs. E&E expense was $11.8 million for 2019 compared to $21.7 million for 2018.
Depletion and Depreciation
Depletion and depreciation expense varies with the carrying amount of the Company's oil and gas properties, the amount of proved
plus probable reserves volumes and the rate of production for the period.
($ thousands except for per boe)
Depletion
Depreciation
Depletion and depreciation
Depletion and depreciation per boe
Years Ended December 31
2019
2018
Change
$
$
$
725,267 $
556,634 $
168,633
6,419
2,050
4,369
731,686 $
558,684 $
173,002
20.52 $
19.02 $
1.50
Depletion and depreciation expense was $731.7 million ($20.52/boe) for 2019 compared to $558.7 million ($19.02/boe) reported for
2018. Total depletion and depreciation expense was higher in 2019 due to the Strategic Combination which resulted in a higher
depletable base and production relative to 2018 which only includes the additional depletion expense after closing on August, 22,
2018. The depletion rate increased following the Strategic Combination in 2018 due to the addition of proved plus probable
reserves at a higher cost than our historical depletion rate.
Impairment
In 2019, we recorded impairment expense of $187.8 million on our Peace River CGU which reflects a sustained decline in heavy oil
prices in Canada which resulted in a change in the development plans for our thermal projects at Peace River. We did not identify
any indicators of impairment or impairment reversals on our remaining CGUs.
In 2018, we recorded total impairments of $285.3 million on our Conventional CGU and our Eagle Ford CGU. We recorded a $65.0
million impairment on our Conventional assets in Canada due to a sustained decline in natural gas prices and a reduction in
planned exploration and development expenditures on these assets. We also recorded a $220.3 million impairment in our Eagle
Ford CGU in 2018 as the rate of future development outlined by the operator was reduced and resulted in a decline in the net
present value of our proved plus probable reserves with no significant changes to proved plus probable reserves volumes. We did
not identify any indicators of impairment or impairment reversals on our remaining CGUs.
Share-Based Compensation Expense
Share-based compensation ("SBC") expense associated with the Share Award Incentive Plan is recognized in net income or loss
over the vesting period of the share awards with a corresponding increase in contributed surplus. The issuance of common shares
upon the conversion of share awards is recorded as an increase in shareholders' capital with a corresponding reduction in
contributed surplus. SBC expense varies with the quantity of unvested share awards outstanding and the grant date fair value
assigned to the share awards.
18
Baytex Energy Corp. 2019 Annual Report
We recorded SBC expense of $15.9 million for 2019 which is lower than $19.5 million reported for 2018. SBC expense is lower in
2019 due to the lower total value of awards granted in 2019 compared to 2018 which included additional SBC expense associated
with the Strategic Combination.
As a result of the Strategic Combination, Baytex became the successor to Raging River's Share Awards Plan, 2012 Option Plan
and 2016 Option Plan (collectively, the "Raging River Plans"). Although no new grants will be made under the Raging River Plans,
share awards and options held under the Raging River Plans in existence at August 22, 2018 were converted to share awards and
options to purchase shares in Baytex.
Foreign Exchange
Unrealized foreign exchange gains and losses represent the change in value of the long-term notes and bank loan denominated in
U.S. dollars. The long-term notes and bank loan are translated to Canadian dollars on the balance sheet date using the closing
CAD/USD exchange rate. When the Canadian dollar strengthens against the U.S. dollar at the end of the current period compared
to the previous period an unrealized gain is recorded and conversely when the Canadian dollar weakens at the end of the current
period compared to the previous period an unrealized loss is recorded. Realized foreign exchange gains and losses are due to
day-to-day U.S. dollar denominated transactions occurring in our Canadian operations.
($ thousands except for exchange rates)
Unrealized foreign exchange (gain) loss
Realized foreign exchange loss
Foreign exchange (gain) loss
CAD/USD exchange rates:
At beginning of period
At end of period
Years Ended December 31
2019
2018
(62,753) $
106,143 $
966
2,151
Change
(168,896)
(1,185)
(61,787) $
108,294 $
(170,081)
$
$
1.3646
1.2965
1.2518
1.3646
We recorded an unrealized foreign exchange gain of $62.8 million for 2019 due to a strengthening of the Canadian dollar relative to
the U.S. dollar at December 31, 2019 compared to December 31, 2018. The Canadian dollar weakened relative to the U.S. dollar
at December 31, 2018 compared to December 31, 2017 which resulted in an unrealized foreign exchange loss of $106.1 million in
2018.
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 loss of $1.0 million for 2019
compared to a loss of $2.2 million for 2018.
Income Taxes
($ thousands)
Current income tax expense (recovery)
Deferred income tax recovery
Total income tax recovery
Years Ended December 31
2019
2,093 $
(68,555)
(66,462) $
2018
(35) $
(101,732)
(101,767) $
Change
2,128
33,177
35,305
$
$
Current income expense was $2.1 million for 2019 compared to a nominal recovery recorded in 2018. The current tax expense for
2019 reflects state taxes owing on our U.S. operations.
We recorded a deferred income tax recovery of $68.6 million for 2019 compared to $101.7 million for 2018. We recorded a lower
deferred income tax recovery in 2019 primarily due to the increase in adjusted funds flow relative to 2018. The deferred tax
recovery for 2019 includes a $6.1 million recovery associated with the reduction in corporate tax rates in Alberta along with a $44.6
million recovery associated with the impairment of oil and gas properties. In 2018 the deferred income tax recovery included a
$63.4 million recovery associated with the impairment of oil and gas properties.
In June 2016, certain indirect subsidiaries received reassessments from the Canada Revenue Agency (the "CRA”) that deny $591
million of non-capital loss deductions relevant to the calculation of income taxes for the years 2011 through 2015. In September
2016, we filed notices of objection with the CRA appealing each reassessment received. There has been no change in the status of
these reassessments since an Appeals Officer was assigned to our file in July 2018. We remain confident that our original tax
filings are correct and intend to defend these tax filings through the appeals process.
Baytex Energy Corp. 2019 Annual Report
19
Canadian Tax Pools ($ 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
($ 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 (loss)
Realized foreign exchange (loss) gain
Other income
Current income tax (expense) recovery
Payments on onerous contracts
Adjusted funds flow
Transaction costs
Exploration and evaluation
Depletion and depreciation
Share based compensation
Non-cash financing and accretion
Unrealized financial derivatives (loss) gain
Unrealized foreign exchange gain (loss)
Gain on dispositions
Impairment
Deferred income tax recovery
Payments on onerous contracts
Net income (loss) for the period
December 31, 2018
529,044
765,289
8,875
502,320
593,251
33,866
2,432,645
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 $
$
$
$
$
180,367
133,345
69,138
1,140,579
407,654
1,931,083
Change
377,049
(6,487)
370,562
(86,124)
(7,073)
37
277,402
356
(3,099)
148,785
1,185
6,354
(2,128)
588
429,443
13,074
9,965
(173,002)
3,640
(3,680)
(199,532)
168,896
292
97,519
(33,177)
(588)
312,850
$
$
$
Years Ended December 31
2019
1,805,919 $
(320,241)
1,485,678
2018
1,428,870 $
(313,754)
1,115,116
(397,716)
(43,942)
(68,795)
975,225 $
(45,469)
(107,417)
75,620
(966)
7,526
(2,093)
—
902,426 $
—
(11,764)
(731,686)
(15,894)
(18,448)
(82,817)
62,753
2,238
(187,822)
68,555
—
(311,592)
(36,869)
(68,832)
697,823 $
(45,825)
(104,318)
(73,165)
(2,151)
1,172
35
(588)
472,983 $
(13,074)
(21,729)
(558,684)
(19,534)
(14,768)
116,715
(106,143)
1,946
(285,341)
101,732
588
$
(12,459) $
(325,309) $
We generated adjusted funds flow of $902.4 million for 2019, an increase of $429.4 million from adjusted funds flow of $473.0
million reported for 2018. Operating netback for 2019 was $277.4 million higher than 2018 due to increased production along with
improved oil price realizations in Canada due to tighter differentials and a decrease in our average royalty rate as a result of the
Strategic Combination. We recorded realized gains on financial derivatives of $75.6 million in 2019 compared to realized losses of
20
Baytex Energy Corp. 2019 Annual Report
$73.2 million in 2018 which also contributed to the $429.4 million increase in adjusted funds flow. The $429.4 million increase in
adjusted funds flow contributed to the $312.9 million decrease in our net loss to $12.5 million for 2019 compared to a net loss of
$325.3 million in 2018. In 2019, we recorded impairments of $187.8 million due to a sustained decline in Canadian heavy oil prices
which resulted in a change in development plans for our thermal projects at Peace River compared to total impairments of $285.3
million in 2018 related to our Conventional and Eagle Ford assets.
Other Comprehensive Income (Loss)
Other comprehensive income or loss is comprised of the foreign currency translation adjustment on U.S. net assets not recognized
in income or loss. The $111.7 million foreign currency translation loss for 2019 relates to the change in value of our U.S. net assets
expressed in Canadian dollars and is due to the strengthening of the Canadian dollar against the U.S. dollar. The CAD/USD
exchange rate was 1.2965 as at December 31, 2019 compared to 1.3646 as at December 31, 2018.
Capital Expenditures
Years Ended December 31
2019
2018
($ thousands)
Canada
U.S.
Total
Canada
U.S.
Total
Drilling, completion and equipping
$
319,417 $
166,094 $
485,511 $
225,904 $
178,665 $
404,569
Facilities
Land, seismic and other
Total exploration and development
Acquisitions, net of proceeds from
divestitures
Strategic Combination (1)
$
$
$
41,141
13,805
10,220
1,614
51,361
15,419
58,813
17,400
14,605
334
73,418
17,734
374,363 $
177,928 $
552,291 $
302,117 $
193,604 $
495,721
2,180 $
— $
— $
— $
2,180 $
(1,818) $
— $ 1,605,668 $
— $
(1,818)
— $ 1,605,668
(1)
Includes $1,239.0 million of consideration associated with 315.3 million common shares issued by Baytex at a closing share price of $3.93 per
common share along with $3.1 million of share based compensation and assumed net debt of $363.6 million.
Exploration and development expenditures were $552.3 million for 2019 compared to $495.7 million for 2018. Higher exploration
and development expenditures in 2019 relative to 2018 reflects the additional activity associated with our Viking and Duvernay light
oil properties which were acquired during Q3/2018 as part of the Strategic Combination.
In Canada, we invested $374.4 million on exploration and development activities in 2019 which is $72.2 million higher than $302.1
million in 2018. Exploration and development activity in 2019 includes 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 $13.8 million of associated facility expenditures.
Total exploration and development costs were higher in 2019 as 2018 only includes exploration and development activity on our
Viking and Duvernay properties after closing of the Strategic Combination in August 2018. Exploration and development activity in
2018 includes costs associated with drilling 125 (87.0 net) light oil wells, 99 (74.9 net) heavy oil wells, 9 (9.0 net) stratigraphic wells
along with $17.4 million of associated facility expenditures.
Total U.S. exploration and development expenditures were $177.9 million for 2019 which is $15.7 million lower than $193.6 million
for 2018. The decrease in exploration and development expenditures in 2019 relative to 2018 reflects slightly lower drilling and
completion activity along with a reduction in facility expenditures required to support current production levels on our Eagle Ford
properties. During 2019 we participated in drilling 96 (20.2 net) wells and commenced production from 109 (25.1 net) wells
compared to 91 (20.8 net) wells drilled and 120 (26.2 net) wells on production during 2018.
We completed minor acquisition and disposition activity in 2019 for net consideration of $2.2 million compared to net proceeds of
$1.8 million in 2018.
Baytex Energy Corp. 2019 Annual Report
21
CAPITAL RESOURCES AND LIQUIDITY
Our capital management objective is to maintain 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, 2019, our capital structure was comprised of shareholders' capital, long-term
notes, working capital and our bank loan.
The capital intensive nature of our operations requires us to maintain adequate sources of liquidity to fund ongoing exploration and
development. 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 sustain our operations and 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 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.
Management of debt is a priority for Baytex in order to sustain operations and support our plans to deliver shareholder value. At
December 31, 2019, net debt of $1,871.8 million was $393.4 million lower than $2,265.2 million at December 31, 2018. The
decrease in net debt is primarily a result of debt repayment from the free cash flow of $328.8 million generated in 2019. Net debt
was also lower at December 31, 2019 due to a strengthening of the Canadian dollar which resulted in a $62.8 million decrease in
the reported principal amount of our U.S. dollar denominated net debt relative to December 31, 2018.
We monitor our capital structure and liquidity requirements using a net debt to adjusted funds flow ratio on a twelve month trailing
basis. At December 31, 2019, our net debt to adjusted funds flow ratio was 2.1 compared to a ratio of 3.1 as at December 31,
2018. The decrease in the net debt to adjusted funds flow ratio relative to December 31, 2018 is attributed to higher adjusted funds
flow combined with a $393.4 million decrease in net debt at December 31, 2019.
Bank Loan
At December 31, 2019, the principal amount of bank loan and letters of credit outstanding was $521.7 million and we had
approximately $523.8 million of undrawn capacity under our credit facilities that total approximately $1,045.5 million. Our facilities
include US$575 of revolving credit facilities (the "Revolving Facilities") and a CAD$300 million non-revolving term loan (the "Term
Loan").
On March 3, 2020, we amended our credit facilities to extend the maturities of the Revolving Facilities and the Term Loan to April 2,
2024. The maturity of the credit facilities will automatically extend 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 at 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. 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,
plus applicable margins. In the event that Baytex exceeds any of the covenants under the credit facilities, Baytex may be required
to repay, refinance or renegotiate the loan terms and may be restricted from taking on further debt or paying dividends to
shareholders.
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 for 2019 was 4.0% as compared to 4.3% for 2018.
22
Baytex Energy Corp. 2019 Annual Report
Financial Covenants
The following table summarizes the financial covenants applicable to the credit facilities and Baytex's compliance therewith as at
December 31, 2019.
Covenant Description
Senior Secured Debt(1) to Bank EBITDA(2) (Maximum Ratio)
Interest Coverage(3) (Minimum Ratio)
Position as at
December 31, 2019
0.52:1.00
9.42:1.00
Covenant
3.50:1.00
2.00:1.00
(1)
"Senior Secured Debt" is defined as the principal amount of the bank loan and other secured obligations identified in the credit agreement. As
at December 31, 2019, the Company's Senior Secured Debt totaled $521.7 million which includes $506.5 million of principal amounts
outstanding and $15.2 million of letters of credit.
(2) 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, 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, 2019 was $1,011.9 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, 2019 were $107.4 million.
(3)
Long-Term Notes
At December 31, 2019 we had three series of long-term notes outstanding that total $1,337.2 million. The long-term notes do not
contain any significant financial maintenance covenants. The long-term notes contain a debt incurrence covenant that restricts our
ability to raise additional debt beyond the existing credit facilities and long-term notes unless the Company maintains a minimum
coverage ratio (computed as the ratio of Bank EBITDA (as defined above) to financing and interest expense on a trailing twelve
month basis) of 2.50:1.00. As at December 31, 2019, the fixed charge coverage ratio was 8.04:1.00.
On February 5, 2020, we issued US$500 million of senior unsecured notes bearing interest at 8.75% payable semi-annually which
mature on April 1, 2027 (the "8.75% Senior Notes"). These 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 $12.4 million
were incurred in conjunction with the issuance which resulted in net proceeds of $652.3 million.
On February 20, 2020, we used a portion of the net proceeds from the issuance of the 8.75% Senior Notes to redeem our US$400
million principal amount of our 5.125% senior unsecured notes due June 1, 2021 at par plus accrued interest. We also issued a
redemption notice for the $300 million principal amount of our 6.625% senior unsecured notes due July 19, 2022 for early
redemption on March 6, 2020 at 101.104% of the principal amount plus accrued interest.
On September 13, 2019, we completed the early redemption of the US$150 million ($198.1 million) principal amount of 6.75%
senior unsecured notes, due February 17, 2011.
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") and US$400 million of 5.625% notes due June 1, 2024 (the "5.625% Notes"). The 5.125%
Notes and the 5.625% Notes pay interest semi-annually with the principal amount repayable at maturity. On February 20, 2020, we
completed the early redemption of the US$400 million principal amount of 5.125% Notes at par plus accrued interest. As of June 1,
2019, the 5.625% Notes are redeemable at our option, in whole or in part, at specified redemption prices and will be redeemable at
par from June 1, 2022 to maturity.
Shareholders’ Capital
We are authorized to issue an unlimited number of common shares and 10.0 million preferred shares. The rights and terms of the
preferred shares are determined upon issuance. During the year ended December 31, 2019, we issued 4.2 million common shares
pursuant to our share-based compensation program. As at March 3, 2020, we had 560.5 million common shares issued and
outstanding and no preferred shares issued and outstanding.
Baytex Energy Corp. 2019 Annual Report
23
Contractual Obligations
Baytex has a number of financial obligations that are incurred in the ordinary course of business. These obligations are of a
recurring nature and impact the Company's cash flow from operations in an ongoing manner. A significant portion of these
obligations will be funded by adjusted funds flow. These obligations as of December 31, 2019 and the expected timing for funding
these obligations are noted in the table below.
($ thousands)
Trade and other payables
Bank loan(1) (2)
Long-term notes(2)
Interest on long-term notes(3)
Lease obligations
Processing agreements
Transportation agreements
Total
Total
207,454 $
506,471
1,337,200
217,247
14,568
39,352
115,999
2,438,291 $
$
$
Less than
1 year
207,454 $
—
—
75,625
6,216
10,234
11,636
311,165 $
1-3 years
3-5 years Beyond 5 years
— $
506,471
818,600
100,303
7,748
10,591
41,263
1,484,976 $
— $
—
518,600
41,319
604
8,848
37,099
606,470 $
—
—
—
—
—
9,679
26,001
35,680
(1) At December 31, 2019, the bank loan was set to mature on April 2, 2021. On March 3, 2020, we amended the bank loan to extend maturity to
April 2, 2024 which 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.
(2) Principal amount of instruments. On February 5, 2020, we issued US$500 million principal amount of 8.75% senior unsecured notes due 2027
and issued a redemption notice for the $300 million principal amount of 6.625% senior unsecured notes due 2022. We expect to complete the
redemption of these notes on March 6, 2020. On February 20, 2020 we completed the redemption of the US$400 million principal amount of
senior unsecured notes due 2021.
(3) Excludes interest on bank loan as interest payments on bank loans fluctuate based on interest rate and bank loan balance.
We also have ongoing obligations related to the abandonment and reclamation of well sites and facilities when they reach the end
of their economic lives. Programs to abandon and reclaim well sites and facilities are undertaken regularly in accordance with
applicable legislative requirements.
24
Baytex Energy Corp. 2019 Annual Report
FOURTH QUARTER 2019 OPERATING AND FINANCIAL RESULTS
($ thousands except for per boe)
Canada
U.S.
Total
Canada
U.S.
Total
Three Months Ended December 31
2019
2018
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 ($/bbl) (1)
NGL ($/bbl)
Natural gas ($/mcf)
Total sales, net of blending and other per boe
Royalties per boe
Operating expense per boe
Transportation expense per boe
21,531
27,050
1,170
49,751
48,260
57,794
22,375
—
7,529
29,904
51,975
38,566
43,906
27,050
8,699
79,655
100,235
96,360
23,978
26,339
1,189
51,506
53,682
60,453
21,009
—
9,138
30,147
49,742
38,437
44,987
26,339
10,327
81,653
103,424
98,890
$
65.31 $
76.46 $
71.00 $
40.55 $
83.28 $
40.32
16.22
2.39
45.52
(4.73)
(14.41)
(1.66)
—
18.75
3.20
52.33
(14.69)
(6.47)
—
40.32
18.41
2.81
48.25
(8.72)
(11.23)
(1.00)
13.65
26.84
1.67
24.04
(3.10)
(13.42)
(1.98)
—
30.37
5.35
59.66
(17.68)
(6.56)
—
60.50
13.65
29.96
3.44
37.89
(8.77)
(10.76)
(1.21)
Operating netback per boe
$
24.72 $
31.17 $
27.30 $
5.54 $
35.42 $
17.15
Financial
Petroleum and natural gas sales
$ 260,217 $ 185,678 $ 445,895 $ 147,472 $ 210,965 $ 358,437
Royalties
Revenue, net of royalties
Operating expense
Transportation expense
Blending and other expense
Operating netback
Realized financial derivatives (loss) gain
General and administrative
Cash interest
Other
Adjusted funds flow
Net income (loss)
(25,154)
(52,128)
(77,282)
(17,229)
(62,536)
(79,765)
235,063
133,550
368,613
130,243
148,429
278,672
(76,623)
(22,950)
(99,573)
(74,663)
(23,194)
(97,857)
(8,840)
(18,167)
—
—
(8,840)
(18,167)
(10,994)
(13,755)
—
—
(10,994)
(13,755)
$ 131,433 $ 110,600 $ 242,033 $
30,831 $ 125,235 $ 156,066
—
—
—
—
—
—
—
—
22,956
(9,893)
(24,389)
1,440
—
—
—
—
—
—
—
—
(3,063)
(14,096)
(27,933)
(146)
$ 131,433 $ 110,600 $ 232,147 $
30,831 $ 125,235 $ 110,828
$ (134,348) $
44,937 $ (117,772) $ (122,645) $ (133,752) $ (231,238)
Exploration and development expenditures
$ 104,460 $
48,657 $ 153,117 $ 125,507 $
58,655 $ 184,162
Acquisitions, net of proceeds from divestitures
$
563 $
— $
563 $
183 $
— $
183
Net debt
$1,871,791
$2,265,167
Baytex Energy Corp. 2019 Annual Report
25
Benchmark Averages
WTI oil (US$/bbl)(1)
LLS oil (US$/bbl)(2)
LLS oil differential to WTI (US$/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
2019
56.96
60.73
3.77
68.10
(5.37)
54.29
(15.83)
2.34
2.50
1.3201
2018
Change
58.81
66.64
7.83
42.68
(26.51)
25.62
(39.42)
1.94
3.64
1.3215
(1.85)
(5.91)
(4.06)
25.42
21.14
28.67
23.59
0.40
(1.14)
(0.0014)
(1) WTI refers to the arithmetic average of NYMEX prompt month WTI for the applicable period.
(2) LLS refers to the Argus trade month average for Louisiana Light Sweet oil.
(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.
We delivered strong operating and financial results in Q4/2019. We invested $153.1 million on exploration and development
expenditures in Q4/2019 and generated adjusted funds flow of $232.1 million. Production of 96,360 boe/d for Q4/2019 was
consistent with expectations and contributed to annual production for 2019 that exceeded our annual guidance of approximately
97,000 boe/d. Free cash flow of $72.9 million in Q4/2019 was used for debt reduction and contributed to a $99.5 million reduction
in net debt relative to Q3/2019.
In Canada, production averaged 57,794 boe/d in Q4/2019 which is 2,659 boe/d lower than 60,453 boe/d reported for Q4/2018. The
decrease in production reflects lower exploration and development activity in the second half of 2019 relative to the same period of
2018. Our weighted average realized price of $45.52/boe for Q4/2019 was $21.48/boe higher than $24.04/boe for Q4/2018 which
was impacted by a significant widening of light and heavy oil differentials. In Q4/2019, the Edmonton Par benchmark price traded at
a US$5.37/bbl discount to WTI while the WCS differential was a US$15.83/bbl discount to WTI compared to Q4/2018 when
Edmonton par traded at a US$26.51/bbl discount to WTI and the WCS heavy oil differential was US$39.42/bbl. Operating netback
of $131.4 million ($24.72/boe) for Q4/2019 is $100.6 million ($19.18/boe) higher than $30.8 million ($5.54/boe) reported for the
same period of 2018. Exploration and development expenditures of $104.5 million in Q4/2019 includes drilling and completion
costs associated with 73 (70.7 net) wells compared to 98 (71.5 net) wells in Q4/2018.
In the U.S., production of 38,566 boe/d for Q4/2019 was consistent with 38,437 boe/d reported for Q4/2018. Our realized price of
$52.33/boe was $7.33/boe lower than our realized price of $59.66/boe in Q4/2018 as a result of the decline in U.S. crude oil
pricing. The LLS benchmark averaged US$60.73/bbl in Q4/2019 which is US$5.91/boe lower than US$66.64/bbl during Q4/2018.
Operating netback of $110.6 million ($31.17/boe) was $14.6 million ($4.24/boe) lower than $125.2 million ($35.41/boe) for Q4/2018
primarily due to lower benchmark prices and lower realized pricing in Q4/2019. Exploration and development expenditures of $48.7
million in Q4/2019 includes costs associated with drilling 27 (6.3 net) wells and commencing production from 24 (6.5 net) wells.
Exploration and development expenditures were lower in Q4/2019 due to the timing of drilling and completion activity relative to
Q4/2018 when we drilled 19 (3.3 net) wells and brought 31 (5.9 net) wells on production.
We generated adjusted funds flow of $232.1 million in Q4/2019 which is $121.3 million higher than $110.8 million in Q4/2018. The
increase was driven by stronger realized pricing in Canada and resulted in operating netback of $27.30/boe in Q4/2019 which is
$10.15/boe higher relative to $17.15/boe in Q4/2018. Production of 96,360 boe/d in Q4/2019 compared to 98,890 boe/d for
Q4/2018 reflects lower exploration and development activity in the second half of relative to the same period of 2018. The increase
in our realized price more than offset the impact of lower production and resulted in an $86.0 million increase in operating netback
in Q4/2019 compared to Q4/2018. Lower G&A expense and cash interest expense combined with realized gains on financial
derivatives also contributed to the increase in adjusted funds flow in Q4/2019 relative to the same period of 2018. G&A expense of
$9.9 million in Q4/2019 was lower than $14.1 million in Q4/2018 which reflects the efficiencies we were able to realize as a result of
the Strategic Combination. Interest expense of $24.4 million in Q4/2019 was $3.5 million lower than $27.9 million for Q4/2018 due
the reduction in net debt including the early redemption of the US$150 million senior unsecured notes in September 2019 which
resulted in lower interest on our long-term notes. We recorded hedging gains of $23.0 million in Q4/2019 compared to hedging
losses of $3.1 million in Q4/2018.
We recorded a net loss of $117.8 million in Q4/2019 compared to net loss of $231.2 million in Q4/2018. The decrease in the net
loss for Q4/2019 was primarily a result of the increase in adjusted funds flow which was $110.8 million higher than Q4/2018 due to
narrower Canadian oil differentials and stronger realized pricing in Canada. The net loss for Q4/2019 includes a $187.8 million
26
Baytex Energy Corp. 2019 Annual Report
impairment expense recorded in Q4/2019 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. The net loss for Q4/2018 includes a $285.3 million impairment expense
recorded in Q4/2018 due to a change in development plans for our Conventional and Eagle Ford properties. The impact of higher
adjusted funds flow and lower impairment expense in Q4/2019 were offset by a loss of $27.5 million associated with unrealized
changes in the carrying value of our financial derivatives and our U.S. denominated debt compared to a gain of $113.8 million in
Q4/2018.
QUARTERLY FINANCIAL INFORMATION
($ thousands, except per
common share amounts)
Petroleum and natural gas sales
Net income (loss)
Per common share - basic
Per common share - diluted
Q4
445,895
(117,772)
(0.21)
(0.21)
2019
2018
Q3
Q2
Q1
Q4
Q3
Q2
Q1
424,600
482,000
453,424
358,437
436,761
347,605
286,067
15,151
78,826
11,336
(231,238)
27,412
(58,761)
(62,722)
0.03
0.03
0.14
0.14
0.02
0.02
(0.42)
(0.42)
0.07
0.07
(0.25)
(0.25)
(0.27)
(0.27)
Adjusted funds flow
232,147
213,379
236,130
220,770
110,828
171,210
106,690
84,255
Per common share - basic
Per common share - diluted
Exploration and development
Canada
U.S.
Acquisitions, net of divestitures
Net debt
Total assets
Common shares outstanding
0.42
0.42
153,117
104,460
48,657
563
1,871,791
5,914,083
558,305
0.38
0.38
0.42
0.42
139,085
106,246
96,774
42,311
(30)
68,259
37,987
1,647
0.40
0.40
153,843
104,870
48,973
—
0.20
0.20
184,162
125,507
58,655
229
0.46
0.45
139,195
94,477
44,718
0.45
0.45
78,830
30,608
48,222
0.36
0.36
93,534
51,525
42,009
—
(21)
(2,026)
1,971,339
2,028,686
2,175,241
2,265,167
2,112,090
1,784,835
1,783,379
6,233,875
6,222,190
6,359,157
6,377,198
6,491,303
4,476,906
4,433,074
557,972
556,798
555,872
554,060
553,950
236,662
236,578
Daily production
Total production (boe/d)
Canada (boe/d)
U.S. (boe/d)
Benchmark prices
WTI oil (US$/bbl)
WCS heavy (US$/bbl)
CAD/USD avg exchange rate
AECO gas ($/mcf)
NYMEX gas (US$/mmbtu)
Sales price ($/boe)
(1)
Royalties ($/boe)
Operating expense ($/boe)
Transportation expense ($/boe)
Operating netback ($/boe)
Realized financial derivatives
gain (loss) ($/boe)
Operating netback after
financial derivatives ($/boe)
96,360
57,794
38,566
56.96
41.13
1.3201
2.34
2.50
48.25
(8.72)
(11.23)
(1.00)
27.30
2.59
29.89
94,927
58,134
36,793
98,402
58,580
39,822
101,115
60,018
41,097
98,890
60,453
38,437
82,412
45,214
37,198
70,664
34,042
36,622
69,522
33,505
36,017
56.45
44.21
59.81
49.14
54.90
42.61
58.81
19.39
69.50
47.25
67.88
48.61
62.87
38.59
1.3207
1.3376
1.3293
1.3215
1.3070
1.2911
1.2651
1.04
2.23
47.14
(8.59)
(11.15)
(1.13)
26.27
1.17
2.64
51.49
(9.67)
(11.22)
(1.33)
29.27
1.94
3.15
47.98
(8.94)
(11.02)
(1.46)
26.56
1.94
3.64
37.89
(8.77)
(10.76)
(1.21)
17.15
1.35
2.90
55.03
(12.13)
(10.25)
(1.26)
31.39
1.03
2.80
51.22
(12.01)
(10.91)
(1.22)
27.08
1.85
3.00
42.96
(10.36)
(10.53)
(1.36)
20.71
2.39
1.45
2.07
(0.34)
(4.07)
(4.57)
(1.57)
28.66
30.72
28.63
16.81
27.32
22.51
19.14
(1) Realized heavy oil prices are calculated based on sales volumes and sales dollars, net of blending and other expense.
In Q4/2019 we delivered our fifth consecutive quarter of strong operating and financial results following closing of the Strategic
Combination in Q3/2018. Production has increased from 69,522 boe/d during Q1/2018 to a high of 101,115 boe/d during Q1/2019
as a result of the Strategic Combination along with our successful development programs in the U.S. and Canada. As planned,
production was lower in Q3/2019 and began to increase in Q4/2019 as a result of the timing of our exploration and development
activity during 2019. Improved well productivity from enhanced completion techniques resulted in relatively consistent average daily
production in the U.S. despite lower quarterly exploration and development expenditures.
In Canada, our exploration and
development program was focused on our heavy oil properties at Peace River and Lloydminster. Exploration and development
activity in Canada increased following the Strategic Combination with the addition of our Viking and Duvernay light oil properties.
Baytex Energy Corp. 2019 Annual Report
27
Global benchmark prices for crude oil have fluctuated over the last eight quarters as attempts to balance the market with
production cuts have been mitigated by increasing production in North America and concerns over global demand. Our realized
pricing in Canada improved in 2019 after a narrowing of light and heavy oil differentials along with a higher weighting of light oil
production following the Strategic Combination. The WCS benchmark averaged US$41.13/bbl in Q4/2019 compared to US$19.39/
bbl in Q4/2018.
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 began to improve in 2018 as commodity prices strengthened and
continued to improve through Q3/2019 following the Strategic Combination. Increased production and strong price realizations due
to a higher proportion of light oil production resulted in adjusted funds flow of $232.1 million in Q4/2019 compared to $84.3 million
in Q1/2018.
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. We
generated free cash flow of $328.8 million in 2019 which was directed towards debt repayment and resulted in net debt of $1,871.8
million at Q4/2019 which is only $88.4 million higher than $1,783.4 million at Q1/2018 despite the additional $363.6 million of net
debt assumed in conjunction with the Strategic Combination.
OFF BALANCE SHEET TRANSACTIONS
We do not have any financial arrangements that are excluded from the consolidated financial statements as at December 31, 2019,
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 natural gas liquids ("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.
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.
28
Baytex Energy Corp. 2019 Annual Report
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
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.
to management
Business Combinations
Business combinations are accounted for using the acquisition method of accounting when the assets acquired meet the definition
of a business in accordance with IFRS.
Determination of the acquirer in a business combination requires management judgment. In determining the acquirer in a business
combination, factors such as voting rights of all equity instruments, the intended corporate governance structure, composition of
senior management of the combined company, and various metrics used to evaluate the relative size of each company are
considered.
The determination of fair value assigned to assets acquired and liabilities assumed requires management to make assumptions
and estimates including forecast benchmark commodity prices, estimates of reserves acquired and discount rates used to present
value future cash flows. Changes in any of the assumptions or estimates used in determining the fair value of assets acquired and
liabilities assumed could impact the amounts assigned to assets, liabilities and goodwill.
Financial Derivatives
Financial derivatives are measured at fair value on each reporting date. The Company uses quoted commodity prices, estimates of
future volatility prices and interest rates available at period end to determine the fair value of outstanding financial derivatives.
Changes in market pricing between period end and settlement of the derivative contracts could have a significant impact on
financial results related to the financial derivatives.
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.
CURRENT AND FUTURE CHANGES IN ACCOUNTING POLICIES
Changes in significant accounting policies
Leases
Baytex adopted IFRS 16 Leases on January 1, 2019, using the modified retrospective approach. The modified retrospective
approach does not require restatement of comparative financial information as it recognizes the cumulative effect on transition as
an adjustment to opening retained earnings and applies the standard prospectively. Comparative information in the Company's
Baytex Energy Corp. 2019 Annual Report
29
consolidated statements of financial position, consolidated statements of loss and comprehensive loss, consolidated statements of
changes in equity, and consolidated statements of cash flows has not been restated and continues to be accounted for in
accordance with the Company's previous accounting policy found in the 2018 annual financial statements.
The cumulative effect of initial application of the standard was to recognize an $18.0 million increase to right-of-use assets ("lease
assets"), a $2.0 million reduction of onerous contracts and a $18.0 million increase to lease obligations. Initial measurement of the
lease obligation was determined based on the remaining lease payments at January 1, 2019 using a weighted averaged
incremental borrowing rate of approximately 3.9%. The lease assets were initially recognized at an amount equal to the lease
obligations. The lease assets and lease obligations recognized largely relate to the Company's head office lease in Calgary.
The adoption of IFRS 16 using the modified retrospective approach allowed the Company to use the following practical expedients
in determining the opening transition adjustment:
•
•
•
•
•
The weighted average incremental borrowing rate in effect at January 1, 2019 was used as opposed to the rate in effect at
inception of the lease;
Leases with a remaining term of less than 12 months as at January 1, 2019 were accounted for as short-term leases;
Leases with an underlying asset of low value are recorded as an expense and not recognized as a lease asset;
Leases with similar characteristics were accounted for as a portfolio using a single discount rate; and
Used the Company's previous assessment under IAS 37, "Provisions, Contingent Liabilities and Contingent Assets' for
onerous contracts instead of reassessing the lease assets for impairment at January 1, 2019.
The Company's accounting policy for leases effective January 1, 2019 is set forth below. The Company applied IFRS 16 using the
modified retrospective approach. Comparative information continues to be accounted for in accordance with the Company's
previous accounting policy found in the 2018 annual financial statements.
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.
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. Transaction costs associated with the Strategic Combination are excluded from adjusted
30
Baytex Energy Corp. 2019 Annual Report
funds flow as we consider the costs non-recurring and not reflective of our ability to generate adjusted funds flow on an ongoing
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
Transaction costs
Adjusted funds flow
Exploration and Development Expenditures
Years Ended December 31
2019
834,939 $
52,070
15,417
—
902,426 $
2018
485,322
(39,448)
14,035
13,074
472,983
$
$
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 is therefore analyzed separately from our evaluation of the performance of
our exploration and development programs.
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
2019
617,508 $
(62,485)
1,487
(3,667)
(552)
2018
463,272
32,435
2,519
(701)
(1,804)
$
552,291 $
495,721
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. We use free cash flow to evaluate funds
available for debt repayment, common share repurchases, potential future dividends and acquisition and disposition opportunities.
Baytex Energy Corp. 2019 Annual Report
31
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
2019
2018
902,426 $
472,983
(552,291)
(495,721)
(5,956)
(15,417)
328,762 $
—
(14,035)
(36,773)
$
$
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 bank loan and long-term notes outstanding,
including working capital. The current portion of financial derivatives is excluded as the valuation of the underlying contracts is
subject to a high degree of volatility prior to the ultimate settlement. Onerous contracts are excluded from net debt as the
underlying contracts do not represent an available source of liquidity. We use the principal amounts of the bank loan 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 bank loan 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 liquidity or repayment
obligation.
The following table summarizes our calculation of net debt.
($ thousands)
Bank loan(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.
Operating Netback
December 31, 2019
506,471 $
1,337,200
207,454
(5,572)
(173,762)
1,871,791 $
$
$
December 31, 2018
522,294
1,596,323
258,114
—
(111,564)
2,265,167
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 derivative (loss) gain
Operating netback after realized financial derivatives
32
Baytex Energy Corp. 2019 Annual Report
Years Ended December 31
2019
2018
$
1,805,919 $
1,428,870
(68,795)
1,737,124
(320,241)
(397,716)
(43,942)
975,225
75,620
$
1,050,845 $
(68,832)
1,360,038
(313,754)
(311,592)
(36,869)
697,823
(73,165)
624,658
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.
($ thousands)
Net income (loss)
Plus:
Financing and interest
Unrealized foreign exchange loss (gain)
Unrealized financial derivatives loss (gain)
Current income tax recovery
Deferred income tax recovery
Depletion and depreciation
Impairment
Gain on dispositions
Transaction costs
Non-cash items(1)
Adjustment for Strategic Combination (2)
Bank EBITDA
Years Ended December 31
2019
2018
$
(12,459) $
(325,309)
125,865
(62,753)
82,817
2,093
(68,555)
731,686
187,822
(2,238)
—
27,658
—
$
1,011,936 $
119,086
106,143
(116,715)
(35)
(101,732)
558,684
285,341
(1,946)
13,074
41,263
255,800
833,654
(1) Non-cash items include share-based compensation, exploration and evaluation expense and non-cash other expense.
(2)
In accordance with the credit facilities agreements, the calculation of Bank EBITDA is adjusted to reflect the impact of material acquisitions as
if the transaction had occurred on the first day of the relevant period.
CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
As of December 31, 2019, 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.
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, 2019.
Baytex Energy Corp. 2019 Annual Report
33
The effectiveness of our internal control over financial reporting as of December 31, 2019 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, 2019 that have
materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting except for the matters
described below.
Baytex previously excluded business processes acquired through the Strategic Combination on August 22, 2018, from the
Company's evaluation of internal control over financial reporting as permitted by applicable securities laws in Canada and the U.S.
We completed the evaluation and integration of internal controls over financial reporting of Raging River during the third quarter of
2019.
SELECTED ANNUAL INFORMATION
The following table summarizes key annual financial and operating information over the three most recently completed financial
years.
2017
857,975
347,641
1.48
1.47
87,174
0.37
0.37
2019
2018
1,485,678 $
1,115,116 $
902,426 $
472,983 $
1.62 $
1.62 $
1.35 $
1.35 $
(12,459) $
(325,309) $
(0.02) $
(0.02) $
5,914,083 $
506,471 $
1,337,200 $
48.72 $
97,680
(0.93) $
(0.93) $
6,377,198 $
4,372,111
522,294 $
213,376
1,596,323 $
1,489,210
46.31 $
80,458
40.58
70,242
($ 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
Bank loan - principal
Long term notes - principal
Average wellhead prices, net of blending costs ($/boe)
Total production (boe/d)
$
$
$
$
$
$
$
$
$
$
$
34
Baytex Energy Corp. 2019 Annual Report
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 expected exploration and development expenditures and average daily production for 2020; and our expected
royalty rate and operating, transportation, general and administrative and interest expenses for 2020; our expected lease
expenditures and asset retirement obligations settled in 2020; 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 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; and our plans with respect to asset retirement obligation activities. 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: the timing of receipt of
regulatory and shareholder approvals for the Transaction; the ability of the combined company to realize the anticipated benefits
of the Transaction; 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; availability and cost of gathering, processing and pipeline systems; failure to comply with the covenants in our debt
agreements; the availability and cost of capital or borrowing; that our credit facilities may not provide sufficient liquidity or may not
be renewed; risks associated with a third-party operating our Eagle Ford properties; the cost of developing and operating our
assets; depletion of our reserves; public perception and its influence on the regulatory regime; restrictions or costs imposed by
climate change initiatives; risks associated with the exploitation of our properties and our ability to acquire reserves; 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;
variations in interest rates and foreign exchange rates; risks associated with our hedging activities; 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 associated with acquiring, developing and exploring for oil and natural
gas and other aspects of our operations; risks associated with large projects; 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;
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, 2019, to be filed with Canadian securities regulatory
authorities and the U.S. Securities and Exchange Commission not later than March 31, 2020 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.
Baytex Energy Corp. 2019 Annual Report
35
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. Further
information regarding risks and uncertainties affecting our business is contained in our Annual Information Form for the year ended
December 31, 2019 under the "Risk Factors" section.
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, the condition of the Canadian, United
States, European and Asian economies, 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 IFRS. If crude oil and natural gas forecast prices
decline, the carrying value of our assets could be subject to downward revisions and our net earnings could be adversely affected.
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 transport of crude oil into the United States has become inadequate for the amount of
Canadian production being exported to the United States and no pipeline capacity to tidewater allowing access to world markets
has been constructed. 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 to market 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
36
Baytex Energy Corp. 2019 Annual Report
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.
Failure to comply with the covenants in the agreements governing our debt could adversely affect our financial condition
We are required to comply with the covenants in our credit facilities and long-term notes. If we fail to comply with such covenants,
are unable to 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 secured 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.
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 markets 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. Should a
lack of financing and uncertainty in the capital markets adversely impact our ability to refinance debt, additional equity may be
issued which could have a dilutive effect on Shareholders. 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 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, which 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. 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.
Our credit facilities may not provide sufficient liquidity and a failure to renew our credit facilities 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
attractive to us, 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. In addition, we are required to repay the long-term
notes at maturity.
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 EF LLC ("Marathon Oil"), a wholly owned subsidiary of Marathon Oil Corporation (NYSE: MRO), 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
Baytex Energy Corp. 2019 Annual Report
37
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.
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 and supply chain
disruptions,
reclamation,
including access to skilled labour. Natural gas, electricity, water, diluent, chemicals, supplies,
abandonment and labour costs are examples of operating and other costs that are susceptible to significant fluctuation.
Our oil and natural gas reserves are a depleting resource and decline as such reserves are produced
Our future oil and natural gas reserves and production, and therefore our cash flow from operating activities, will be highly
dependent on our success in exploiting our reserves base and acquiring additional 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.
in developing our reserves or acquiring additional reserves at acceptable costs.
There is no assurance we will be successful
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 the value of our outstanding securities.
Our ability to add to our oil and natural gas reserves is highly dependent on our success in exploiting existing properties
and acquiring additional reserves
Our long-term commercial success depends on our ability to find, acquire, develop and commercially produce oil and natural gas
reserves. 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 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. New wells we drill or participate in may not become productive and we may not recover all
or any portion of our investment in these wells.
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.
Climate change initiatives may impose restrictions or costs on our business which have a material adverse affect on our
business
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.
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Baytex Energy Corp. 2019 Annual Report
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 on our business.
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.
Implementation of new regulations on hydraulic fracturing may lead to operational delays,
decreased production volumes, adversely affecting the Company's financial position
increased costs and/or
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 Company'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 Company's ability to
fracture its wells or carry out waterflood operations
The Company undertakes or intends to undertake certain hydraulic fracturing and waterflooding programs. To undertake such
operations the Company needs to have access to sufficient volumes of water, or other liquids. There is no certainty that the
Company 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 and waterflooding. If the Company is unable to access such water it may not be able to
undertake hydraulic fracturing or waterflooding activities, which may reduce the amount of oil and natural gas that the Company is
ultimately able to produce from its reservoirs.
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.
Baytex Energy Corp. 2019 Annual Report
39
Regulations regarding the disposal of fluids used in the Company'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 and provincial 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 Company's costs of compliance.
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 which may have an adverse affect on our business
federal, provincial, state and municipal
All phases of our operations are subject to environmental, health and safety regulation pursuant to a variety of Canadian, U.S. and
other
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 provinces of Alberta and Saskatchewan 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. These programs
generally involve an assessment of the ratio of a licensee's deemed assets to deemed liabilities. If a licensee's deemed liabilities
exceed its deemed assets, a security deposit is required. Changes in the ratio of our deemed assets to deemed liabilities or
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.
In addition to regulatory requirements pertaining to the production, marketing and sale of oil and natural gas mentioned above, our
legislation affecting, in particular, foreign investment, through
business and financial condition could be influenced by federal
legislation such as the Competition Act (Canada) and the Investment Canada Act (Canada) and in the United States by the Hart-
Scott-Rodino Antitrust Improvements Act.
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 future growth which may adversely affect the value of our outstanding securities.
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.
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Baytex Energy Corp. 2019 Annual Report
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.
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 the market price of the Common Shares.
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, 2019 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 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 and
terrorism; and other adverse risks to the environment.
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
Baytex Energy Corp. 2019 Annual Report
41
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
to the risk that counterparties to our risk management contracts, marketing arrangements and operating
We are subject
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.
We are subject to a number of additional business risks which could adversely affect our income and financial condition
Our business involves many operating risks related to acquiring, developing and exploring for oil and natural gas which even a
combination of experience, knowledge and careful evaluation may not be able to overcome. Our operational risks include, but are
not limited to: operational and safety considerations; pipeline and rail transportation and interruptions; reservoir performance and
the
technical challenges; partner risks; competition;
availability of drilling and related equipment; our ability to access new technology; seasonality and access restrictions; timing and
success of integrating the business and operations of acquired assets and companies; risk of litigation, regulatory issues, increases
in government taxes and changes to royalty or mineral/severance tax regimes; and risk to our reputation resulting from operational
activities that may cause personal injury, property damage or environmental damage.
land claims; our ability to hire and retain necessary skilled personnel;
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.
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.
Alternatives to and changing demand for petroleum products
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 Company 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 Company's
business and financial condition by decreasing its cash flow from operating activities and the value of its assets.
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Baytex Energy Corp. 2019 Annual Report
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.
Baytex Energy Corp. 2019 Annual Report
43
MANAGEMENT'S 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, 2019, 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, 2019 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, 2019.
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.
March 3, 2020
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Baytex Energy Corp. 2019 Annual Report
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, 2019 and 2018, 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). In our opinion, the
consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December
31, 2019 and 2018, and the results of 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, 2019, based on criteria established in
the Treadway
Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of
Commission, and our report dated March 3, 2020 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 indicators of impairment or impairment reversal related to oil and gas properties
As discussed in note 3 to the consolidated financial statements, when circumstances indicate that a cash-generating unit
(“CGU”) may be impaired or a previous impairment reversed, the Company compares the carrying amount of the CGU to its
recoverable amount. At each reporting date, the Company analyzes indicators of impairment or impairment reversal (“impairment
indicators”) for each CGU, such as significant increases or decreases in reservoir performance (which includes forecasted
production volumes), forecasted royalty, operating and capital costs and forecasted oil and gas prices (collectively “reserve
assumptions”) or resulting cash flows from proved and probable oil and gas reserves (“CGU reserves”). The estimation of CGU
reserves involves the expertise of
reservoir engineering specialists, who take into consideration reserve
assumptions. The Company engages independent reservoir engineering specialists to estimate CGU reserves, which are an
input in the assessment of CGU impairment indicators. The carrying amount of the Company’s oil and gas properties as at
December 31, 2019 was $5,388 million.
independent
We identified the assessment of indicators of impairment or impairment reversal related to oil and gas properties as a critical
audit matter. Changes in circumstances that could indicate a CGU may be impaired or a previous impairment reversed, required
the application of complex auditor judgment. Complex auditor judgment was also required to evaluate the reserve assumptions
used by the Company in their assessment.
The primary procedures we performed to address this critical audit matter included the following. We tested certain internal
controls over the Company’s impairment indicators assessment process, including controls related to the assessment of reserve
assumptions and resulting cash flows of CGU reserves. We evaluated changes in circumstances to the Company or CGUs
identified by the Company against evidence obtained through other procedures. We evaluated the competence, capabilities and
Baytex Energy Corp. 2019 Annual Report
45
objectivity of the independent reservoir engineering specialists, who estimated CGU reserves. We evaluated the methodology
used by the independent reservoir engineering specialists to estimate CGU reserves for compliance with regulatory standards.
We compared current year actual CGU production volumes, royalty, operating and capital costs to the respective reserve
assumptions used in the prior year estimate of proved reserves by CGU to assess the Company’s ability to accurately forecast.
We compared the forecasted commodity prices used in the current year estimate of CGU reserves to those published by
independent reservoir engineering companies. We compared the forecasted production volumes and forecasted royalty,
operating and capital costs assumptions used in the current year estimate of CGU reserves to historical results.
Assessment of the recoverable amount of the Peace River cash generating unit
As discussed in note 7 to the consolidated financial statements, the Company recorded an impairment charge of $180 million
related to the Peace River CGU. The Company identified an indicator of impairment at December 31, 2019 for the Peace River
CGU and performed an impairment test to determine the recoverable amount of the CGU. The determination of recoverable
amount of the CGU involves a number of estimates, including cash flows associated with proved and probable oil and gas
reserves of the Peace River CGU (“Peace River CGU reserves”) and discount rate. The estimation of Peace River CGU reserves
involves the expertise of independent reservoir engineering specialists, who take into consideration reserve assumptions. The
Company engages independent reservoir engineering specialists to estimate the Peace River CGU reserves.
We identified the assessment of the recoverable amount of the Peace River CGU as a critical audit matter. Complex auditor
judgment was required to assess the Company’s estimate of Peace River CGU reserves and discount rate, which were inputs to
the calculation of recoverable amount of the Peace River CGU. Auditor judgment was also required to evaluate the reserve
assumptions used to estimate Peace River CGU reserves.
The primary procedures we performed to address this critical audit matter included the following. We tested certain internal
controls over the Company’s determination of the recoverable amount of the Peace River CGU, including controls related to the
development of the discount rate and the assessment of reserve assumptions and resulting cash flows of the Peace River CGU
reserves. We evaluated the competence, capabilities and objectivity of the independent reservoir engineering specialists, who
estimated the Peace River CGU reserves. We evaluated the methodology used by the independent reservoir engineering
specialists to estimate the Peace River CGU reserves for compliance with regulatory standards. We compared current year
actual CGU production volumes, royalty, operating and capital costs to the respective reserve assumptions used in the prior year
estimate of the proved reserves for the Peace River CGU to assess the Company’s ability to accurately forecast. We compared
the forecasted commodity prices used in the current year estimate of the Peace River CGU reserves to those published by
independent reservoir engineering companies. We compared the forecasted production volumes and forecasted royalty,
operating and capital costs assumptions used in the current year estimate of the Peace River CGU reserves to historical results.
We involved a valuation professional with specialized skills and knowledge, who assisted in evaluating the Company’s discount
rate, by comparing it against publicly available market and other external data. The valuation specialist estimated the recoverable
amount of the Peace River CGU using the estimated of the cash flow associated with the Peace River CGU reserves and the
Company’s discount rate evaluated by the specialist and compared the results to market and other external pricing data.
Assessment of the 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”). For the year ended December 31, 2019, the Company
recorded depletion expense related to oil and gas properties of $725 million. The estimation of area reserves requires the
expertise of independent reservoir engineering specialists, who take into consideration reserve assumptions. The Company
engages independent reservoir engineering specialists to estimate the 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. Complex auditor judgment was required to assess the Company’s estimate of area reserves and the
underlying reserve assumptions.
The primary procedures we performed to address this critical audit matter included the following. We tested certain internal
controls over the Company’s calculation of depletion expense, including controls over the assessment of reserve assumptions
and the resulting area reserves. We evaluated the competence, capabilities and objectivity of
the independent reservoir
engineering specialists, who estimate area reserves. We evaluated the methodology used by the independent reservoir
engineering specialists to estimate area reserves for compliance with regulatory standards. We compared current year actual
area production volumes, royalty, operating and capital costs to respective reserve assumptions used in the prior year estimate
of proved reserves by area to assess the Company’s ability to accurately forecast. We compared the forecasted commodity
prices used in the current year estimate of area reserves to those published by independent reservoir engineering firms. We
compared the forecasted production volumes and forecasted royalty, operating and capital costs assumptions used in the current
year estimate of area reserves to historical results.
46
Baytex Energy Corp. 2019 Annual Report
We have served as the Company’s auditor since 2016.
Chartered Professional Accountants
Calgary, Canada
March 3, 2020
Baytex Energy Corp. 2019 Annual Report
47
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors
Baytex Energy Corp.:
Opinion on Internal Control Over Financial Reporting
We have audited Baytex Energy Corp.’s (the Company) internal control over financial reporting as of December 31, 2019, 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, 2019, 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, 2019 and 2018, and the related
consolidated statements of loss, comprehensive loss, changes in equity, and cash flows for the years then ended, and related
notes (collectively, the consolidated financial statements), and our report dated March 3, 2020 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 Report
on Internal Control over Financial Reporting. 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
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.
the company; (2) provide reasonable assurance that
the assets of
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
March 3, 2020
48
Baytex Energy Corp. 2019 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
LIABILITIES
Current liabilities
Trade and other payables
Lease obligations
Financial derivatives
Onerous contracts
Asset retirement obligations
Non-current liabilities
Bank loan
Long-term notes
Lease obligations
Asset retirement obligations
Deferred income tax liability
SHAREHOLDERS’ EQUITY
Shareholders' capital
Contributed surplus
Accumulated other comprehensive income
Deficit
Commitments and contingencies (note 22)
Subsequent events (notes 10 and 11)
See accompanying notes to the consolidated financial statements.
Notes
December 31, 2019
December 31, 2018
6
7
8
9
9
12
10
11
9
12
17
13
$
$
$
5,572 $
173,762
5,433
184,767
320,210
5,387,889
7,598
13,619
—
111,564
79,582
191,146
358,935
5,817,889
9,228
—
5,914,083 $
6,377,198
207,454 $
258,114
5,798
8,668
—
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 $
—
—
1,986
—
260,100
520,700
1,583,240
—
646,898
310,836
3,321,774
5,701,516
19,137
667,874
(3,333,103)
3,055,424
6,377,198
Naveen Dargan
Director, Baytex Energy Corp.
Gregory K. Melchin
Director, Baytex Energy Corp.
Baytex Energy Corp. 2019 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
2019
2018
16
$
4
6
7, 8, 9
6, 7
14
18
20
19
17
15
15
$
$
$
$
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
1,428,870
(313,754)
1,115,116
311,592
36,869
68,832
45,825
13,074
21,729
558,684
285,341
19,534
119,086
(43,550)
108,294
(1,946)
(1,172)
1,542,192
(427,076)
(35)
(101,732)
(101,767)
(325,309)
204,770
(120,539)
(0.93)
(0.93)
351,542
351,542
Revenue, net of royalties
Petroleum and natural gas sales
Royalties
Expenses
Operating
Transportation
Blending and other
General and administrative
Transaction costs
Exploration and evaluation
Depletion and depreciation
Impairment
Share-based compensation
Financing and interest
Financial derivatives loss (gain)
Foreign exchange (gain) loss
Gain on dispositions
Other income
Net loss before income taxes
Income tax expense (recovery)
Current income tax expense (recovery)
Deferred income tax recovery
Net loss attributable to shareholders
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. 2019 Annual Report
—
—
—
—
Baytex Energy Corp.
Consolidated Statements of Changes in Equity
(thousands of Canadian dollars)
Balance at December 31, 2017
Issued on corporate acquisition
Issuance costs, net of tax
Vesting of share awards
Share-based compensation
Comprehensive income (loss)
Notes
4
4, 13
13
14
Shareholders’
capital
Contributed
surplus
Accumulated
other
comprehensive
income
Deficit
Total equity
$
4,443,576 $
15,999 $
463,104 $
(3,007,794) $
1,914,885
1,238,995
(551)
3,100
—
19,496
(19,496)
19,534
—
—
—
—
—
—
—
—
—
204,770
(325,309)
1,242,095
(551)
—
19,534
(120,539)
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
13
14
17,319
(17,319)
15,894
—
—
—
—
—
15,894
—
(111,650)
(12,459)
(124,109)
Balance at December 31, 2019
$
5,718,835 $
17,712 $
556,224 $
(3,345,562) $
2,947,209
See accompanying notes to the consolidated financial statements.
Baytex Energy Corp. 2019 Annual Report
51
Baytex Energy Corp.
Consolidated Statements of Cash Flows
(thousands of Canadian dollars)
Years Ended December 31
Notes
2019
2018
$
(12,459) $
(325,309)
14
19
6
7, 8, 9
6, 7
18
20
17
12
21
10
13
9
11
6
7
8
21
$
$
$
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 $
19,534
106,143
21,729
558,684
285,341
14,768
(116,715)
(1,946)
(101,732)
(588)
(14,035)
39,448
485,322
(21,295)
(755)
—
—
(22,050)
(10,567)
(485,154)
(1,804)
(701)
2,519
32,435
(463,272)
—
—
—
112,241 $
1,160 $
104,821
—
CASH PROVIDED BY (USED IN):
Operating activities
Net loss
Adjustments for:
Share-based compensation
Unrealized foreign exchange (gain) loss
Exploration and evaluation
Depletion and depreciation
Impairment
Non-cash financing and accretion
Unrealized financial derivatives loss (gain)
Gain on dispositions
Deferred income tax recovery
Payments on onerous contracts
Asset retirement obligations settled
Change in non-cash working capital
Financing activities
Decrease in bank loan
Common share issuance costs
Payments on lease obligations
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. 2019 Annual Report
Baytex Energy Corp.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2019 and 2018
(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 the United States. The Company’s common
shares are traded on the Toronto Stock Exchange and the New York 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 except for the adoption of IFRS 16 Leases as discussed in note 3.
The consolidated financial statements were approved by the Board of Directors of Baytex on March 3, 2020.
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 presentation 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.
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.
Reserves
The Company uses estimates of oil, natural gas and natural gas liquids ("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.
Baytex Energy Corp. 2019 Annual Report
53
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.
Business Combinations
Business combinations are accounted for using the acquisition method of accounting when the assets acquired meet the
definition of a business in accordance with IFRS.
Determination of the acquirer in a business combination requires management judgment. In determining the acquirer in a
business combination, factors such as voting rights of all equity instruments, the intended corporate governance structure,
composition of senior management of the combined company, and various metrics used to evaluate the relative size of each
company are considered.
The determination of fair value assigned to assets acquired and liabilities assumed requires management to make assumptions
and estimates including forecast benchmark commodity prices, estimates of reserves acquired and discount rates used to
present value future cash flows. Changes in any of the assumptions or estimates used in determining the fair value of assets
acquired and liabilities assumed could impact the amounts assigned to assets, liabilities and goodwill.
Financial Derivatives
Financial derivatives are measured at fair value on each reporting date. The Company uses quoted commodity prices, estimates
of future volatility prices and interest rates available at period end to determine the fair value of outstanding financial derivatives.
Changes in market pricing between period end and settlement of the derivative contracts could have a significant impact on
financial results related to the financial derivatives.
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
the future
provision for asset
abandonment and reclamation costs required under current regulatory requirements. Actual abandonment and reclamation costs
could be materially different from estimated amounts.
retirement obligations represents management's best estimate of
the present value of
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.
54
Baytex Energy Corp. 2019 Annual Report
3. SIGNIFICANT ACCOUNTING POLICIES
Changes in significant accounting policies
Leases
Baytex adopted IFRS 16 Leases on January 1, 2019, using the modified retrospective approach. The modified retrospective
approach does not require restatement of comparative financial information as it recognizes the cumulative effect on transition as
an adjustment to opening retained earnings and applies the standard prospectively. Comparative information in the Company's
consolidated statements of financial position, consolidated statements of loss and comprehensive loss, consolidated statements
of changes in equity, and consolidated statements of cash flows has not been restated and continues to be accounted for in
accordance with the Company's previous accounting policy found in the 2018 annual financial statements.
The cumulative effect of initial application of the standard was to recognize an $18.0 million increase to right-of-use assets
("lease assets"), a $2.0 million reduction of onerous contracts and a $18.0 million increase to lease obligations.
Initial
measurement of the lease obligation was determined based on the remaining lease payments at January 1, 2019 using a
weighted averaged incremental borrowing rate of approximately 3.9%. The lease assets were initially recognized at an amount
equal to the lease obligations. The lease assets and lease obligations recognized largely relate to the Company's head office
lease in Calgary.
The adoption of IFRS 16 using the modified retrospective approach allowed the Company to use the following practical
expedients in determining the opening transition adjustment:
•
•
•
•
•
The weighted average incremental borrowing rate in effect at January 1, 2019 was used as opposed to the rate in effect
at inception of the lease;
Leases with a remaining term of less than 12 months as at January 1, 2019 were accounted for as short-term leases;
Leases with an underlying asset of low value are recorded as an expense and not recognized as a lease asset;
Leases with similar characteristics were accounted for as a portfolio using a single discount rate; and
Used the Company's previous assessment under IAS 37, "Provisions, Contingent Liabilities and Contingent Assets' for
onerous contracts instead of reassessing the lease assets for impairment at January 1, 2019.
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 balances and 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.
Baytex Energy Corp. 2019 Annual Report
55
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.
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.
56
Baytex Energy Corp. 2019 Annual Report
The depreciation methods and estimated useful lives for other plant and equipment are as follows:
Classification
Motor Vehicles
Office Equipment
Computer Hardware
Furniture and Fixtures
Leasehold Improvements
Other Assets
Method
Diminishing balance
Diminishing balance
Diminishing balance
Diminishing balance
Straight-line over life of the lease
Diminishing balance
Rate or period
15%
20%
30%
10%
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.
Impairment
Non-derivative financial assets
The Company assesses non-derivative financial assets at each reporting date to determine whether there is any objective
evidence indicating that it is impaired. Objective evidence exists if one or more events have had a negative effect on the
estimated future cash flows of that asset. An impairment loss in respect of a financial asset measured at amortized cost is
calculated as the difference between its carrying amount and the present value of the estimated future cash flows.
An impairment loss is reversed when there is objective evidence that the value of the financial assets has been partially or fully
restored. For financial assets measured at amortized cost the reversal is recognized in net income or loss.
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 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 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.
transactions are considered if available.
In determining FVLCD, recent market
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
Baytex Energy Corp. 2019 Annual Report
57
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.
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, 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
IFRS 9 contains three principal classification categories for initial classification of financial assets: 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
58
Baytex Energy Corp. 2019 Annual Report
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
Bank loan
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.
Debt issuance costs related to the amendment our bank loan 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
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.
income or loss over the term of
the financial
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.
Baytex Energy Corp. 2019 Annual Report
59
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 balance sheet 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.
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. The payout multiplier is dependent on the performance of the Company relative to pre-defined 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 assumed share awards and share options pursuant to a business combination in 2018 (note 4). The share options
were valued at the closing date of the transaction utilizing a Black-Scholes pricing model to value the share options. The share
awards were valued at fair value using the quoted market price of the Company's common shares on the closing date of the
transaction. The share awards assumed consist of restricted share awards and performance share awards with a fixed multiplier
of 1.0. Share-based compensation is expensed over the remaining vesting period and recognized as share-based compensation
expense, with a corresponding increase to contributed surplus.
.
60
Baytex Energy Corp. 2019 Annual Report
4. BUSINESS COMBINATION
On August 22, 2018, Baytex completed a plan of arrangement whereby Baytex acquired, directly and indirectly, all of the issued
and outstanding common shares of Raging River Exploration Inc. (“Raging River”), a publicly traded oil and gas producer with
light oil producing properties in southwest Saskatchewan and Alberta.
The acquisition was accounted for as a business combination whereby the net assets acquired and liabilities assumed were
recorded at fair value at the acquisition date. Consideration consisted of the issuance of 315.3 million Baytex common shares
valued at approximately $1.2 billion (based on the closing price of Baytex’s common shares of $3.93 on the Toronto Stock
Exchange on August 22, 2018). The fair value of oil and gas properties acquired was determined using estimates of proved plus
probable reserves evaluated at December 31, 2018 by an independent reserves evaluator and adjusted for operations between
August 22, 2018 and the effective date of the reserve evaluation. Asset retirement obligations were determined using internal
estimates of the timing and estimated costs associated with the abandonment and reclamation of the wells and facilities acquired
using a market discount rate of 7.5%.The fair value of exploration and evaluation properties was estimated with reference to
recent land sales in similar areas.
The total consideration paid and estimates of the fair value of the assets acquired and liabilities assumed as at the date of the
acquisition are set forth in the table below.
Consideration
Common shares issued
Share-based compensation(1)
Total consideration
Fair value of net assets acquired
Exploration and evaluation assets
Oil and gas properties
Working capital deficiency excluding bank debt and financial derivatives
Financial derivatives
Bank debt(2)
Asset retirement obligations
Deferred income tax liability
Net assets acquired
$
$
$
1,238,995
3,100
1,242,095
97,858
1,748,368
(46,773)
(5,548)
(316,800)
(39,960)
(195,050)
$
1,242,095
(1) Following closing of the transaction, holders of units outstanding under Raging River's share-based compensation plans were entitled to
Baytex common shares rather than Raging River common shares with adjustment to the exercise price or quantity outstanding based on the
exchange ratio for the Raging River shares. As a result, the fair value assigned to the service period that had occurred prior to closing was
recognized by Baytex as additional consideration (see note 14).
(2) On August 22, 2018, Baytex amended its credit facilities to include the credit facility assumed in conjunction with the acquisition of Raging
River and converted outstanding principal amounts to a non-revolving term loan.
The acquisition contributed revenue of $158.8 million and operating income of $98.6 million for the period from the acquisition
date of August 22, 2018 to December 31, 2018. Had the acquisition occurred on January 1, 2018, revenue would have increased
by $379.5 million and operating income would have increased by $273.2 million for the year. Operating income is defined as
revenue, net of royalties, less operating, transportation and blending expense.
In 2018, transaction costs of $13.1 million were expensed as incurred and share issuance costs of $0.6 million (net of taxes of
$0.2 million) were recorded in shareholders' capital in the year.
Baytex Energy Corp. 2019 Annual Report
61
5. 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
2019
2018
2019
2018
2019
2018
2019
2018
Canada
U.S.
Corporate
Consolidated
Revenue, net of royalties
Petroleum and natural gas sales
$ 1,077,724 $ 619,215 $ 728,195 $ 809,655 $
— $
— $ 1,805,919 $ 1,428,870
Royalties
Expenses
Operating
Transportation
Blending and other
General and administrative
Transaction costs
Exploration and evaluation
Depletion and depreciation
Impairment
Share-based compensation
Financing and interest
Financial derivatives loss (gain)
Foreign exchange (gain) loss
Gain on dispositions
Other income
(107,467)
(72,700)
(212,774)
(241,054)
970,257
546,515
515,421
568,601
298,303
221,717
99,413
89,875
36,869
68,832
—
—
10,580
—
—
—
—
—
294,925
261,766
43,942
68,795
—
—
11,764
463,501
187,822
—
—
—
—
65,000
—
—
—
—
(2,238)
(1,946)
—
—
—
—
—
—
—
—
—
—
—
—
—
11,149
261,709
220,341
—
—
—
—
—
—
—
—
—
—
—
45,469
—
—
6,419
—
—
(320,241)
(313,754)
— 1,485,678
1,115,116
—
—
—
45,825
13,074
—
2,050
—
397,716
311,592
43,942
68,795
45,469
—
11,764
731,686
187,822
15,894
36,869
68,832
45,825
13,074
21,729
558,684
285,341
19,534
15,894
19,534
125,865
119,086
125,865
119,086
7,197
(43,550)
7,197
(43,550)
(61,787)
108,294
(61,787)
108,294
—
—
(7,526)
(1,172)
(2,238)
(7,526)
(1,946)
(1,172)
Net income (loss) before income taxes
(101,632)
(149,462)
154,242
(14,473)
(131,531)
(263,141)
(78,921)
(427,076)
1,071,889
695,977
361,179
583,074
131,531
263,141
1,564,599
1,542,192
Income tax expense (recovery)
Current income tax expense (recovery)
Deferred income tax expense (recovery)
101
(32,942)
(32,841)
—
(40,723)
(40,723)
1,992
10,055
12,047
(35)
(26,049)
(26,084)
—
(45,668)
(45,668)
—
2,093
(35)
(34,960)
(34,960)
(68,555)
(101,732)
(66,462)
(101,767)
Net income (loss)
$
(68,791) $ (108,739) $ 142,195 $
11,611 $
(85,863) $ (228,181) $
(12,459) $ (325,309)
Total oil and natural gas capital
expenditures
(1)
$ 376,543 $ 300,299 $ 177,928 $ 193,604 $
— $
— $ 554,471 $ 493,903
(1)
Includes acquisitions, net of proceeds from divestitures.
As at
Canadian assets
U.S. assets
Corporate assets
Total consolidated assets
December 31, 2019
December 31, 2018
$
$
3,484,123 $
2,403,310
26,650
5,914,083 $
3,739,029
2,628,941
9,228
6,377,198
62
Baytex Energy Corp. 2019 Annual Report
6. EXPLORATION AND EVALUATION ASSETS
Balance, beginning of year
Capital expenditures
Corporate acquisition (note 4)
Property acquisitions
Divestitures
Impairment
Property swaps
Exploration and evaluation expense
Transfers to oil and gas properties (note 7)
Foreign currency translation
Balance, end of year
December 31, 2019
December 31, 2018
$
358,935 $
2,948
—
1,523
(443)
(7,822)
417
(11,764)
(16,204)
(7,380)
$
320,210 $
272,974
10,567
97,858
514
(1,021)
—
—
(21,729)
(13,866)
13,638
358,935
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 of $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.
At December 31, 2018 the Company identified indicators of impairment for the exploration and evaluation assets within the
Conventional CGU. The estimated recoverable amount exceeded the carrying value of the of the exploration and evaluation
assets in the Conventional CGU and no impairment was recorded. There were no indicators of impairment for exploration and
evaluation assets in the remaining CGUs at December 31, 2018.
7. OIL AND GAS PROPERTIES
Balance, December 31, 2017
Capital expenditures
Corporate acquisition (note 4)
Property acquisitions
Transfers from exploration and evaluation assets (note 6)
Change in asset retirement obligations (note 12)
Divestitures
Impairment
Foreign currency translation
Depletion
Balance, December 31, 2018
Capital expenditures
Property acquisitions
Transfers from exploration and evaluation assets (note 6)
Change in asset retirement obligations (note 12)
Divestitures
Property swaps
Impairment
Foreign currency translation
Depletion
Balance, December 31, 2019
Accumulated
Cost
depletion Net book value
$
7,932,327 $
(3,974,018) $
3,958,309
485,154
1,748,368
202
13,866
238,662
(15)
—
325,969
—
—
—
—
—
—
—
(285,341)
(110,651)
(556,634)
485,154
1,748,368
202
13,866
238,662
(15)
(285,341)
215,318
(556,634)
$
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
Baytex Energy Corp. 2019 Annual Report
63
Baytex recorded impairment expense related to oil and gas properties of $180.0 million for the year ended December 31, 2019
and $285.3 million for the year ended December 31, 2018.
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 approved by the Board of
Directors and an after-tax discount rate of 11%. The recoverable amount was not sufficient to support the carrying amount of the
the CGU which resulted in an impairment of $180.0 million recorded as at December 31, 2019. There were no indicators of
impairment or impairment reversal identified for the remaining CGUs as at December 31, 2019.
The recoverable amount of the Peace River CGU was calculated at December 31, 2019 using the following benchmark
reference prices for the years 2020 to 2029 adjusted for commodity differentials specific to the Company.
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
WTI crude oil (US$/bbl)
61.00
63.75
66.18
67.91
69.48
71.07
72.68
74.24
75.73
77.24
WCS heavy oil (CA$/bbl)
57.57
62.35
64.33
66.23
67.97
69.72
71.49
73.20
74.80
76.43
AECO (CA$/GJ)
Exchange rate (CAD/USD)
2.04
1.32
2.32
1.30
2.62
1.27
2.71
1.27
2.81
1.27
2.89
1.27
2.96
1.27
3.03
1.27
3.09
1.27
3.16
1.27
This data is combined with assumptions relating to long-term prices, inflation rates and exchange rates together with estimates of
transportation costs and pricing of competing fuels to forecast long-term energy prices, consistent with external sources of
information. The prices and costs subsequent to 2029 have been adjusted for inflation at an annual rate of 2.0%.
The following table demonstrates the sensitivity of the estimated recoverable amount of the Peace River CGU to reasonably
possible changes in key assumptions inherent in the estimate.
Change in impairment expense
Change in discount
rate of 1%
Change in oil price of
$2.50/bbl
$
24,000 $
88,000
At December 31, 2018, indicators of impairment existed for the Conventional CGU due to a sustained decline in Canadian
natural gas prices and a reduction in planned capital exploration and development expenditures. The recoverable amount was
not sufficient to support the carrying amount of the CGU which resulted in an impairment of $65.0 million recorded as at
December 31, 2018. The recoverable amount of the Conventional CGU was based on its VIU which was estimated using a
discounted cash flow model based on an independent reserve report approved by the Board of Directors and a range of pre-tax
discount rates between 8% and 20%.
At December 31, 2018, indicators of impairment existed for the Eagle Ford CGU due to the expected development plan outlined
by the operator which resulted in a decline in the net present value of the cash flows of the proved plus probable reserves. The
recoverable amount was not sufficient
the CGU which resulted in an impairment of
$220.3 million recorded as at December 31, 2018. The recoverable amount of the Eagle Ford CGU was based on its VIU which
was estimated using a discounted cash flow model based on an independent reserve report approved by the Board of Directors
and a range of pre-tax discount rates between 8% and 20%.
the carrying amount of
to support
8. OTHER PLANT AND EQUIPMENT
Balance, December 31, 2017
Capital expenditures
Depreciation
Balance, December 31, 2018
Capital expenditures
Depreciation
Balance, December 31, 2019
64
Baytex Energy Corp. 2019 Annual Report
Accumulated
Cost
depreciation Net book value
$
$
$
62,648 $
(53,174) $
1,804
—
—
(2,050)
64,452 $
(55,224) $
552
—
—
(2,182)
65,004 $
(57,406) $
9,474
1,804
(2,050)
9,228
552
(2,182)
7,598
9. LEASES
Lease Assets
Baytex had the following right-of-use assets at December 31, 2019.
Balance, January 1, 2019 (1)
Additions
Modifications
Depreciation
Balance, December 31, 2019
Office Leases
14,775 $
—
(6)
(4,904)
9,865 $
$
$
Field
Equipment
Vehicles and
Other
2,254 $
1,668
4
(837)
969 $
159
19
(482)
3,089 $
665 $
Total
17,998
1,827
17
(6,223)
13,619
(1) The Company adopted IFRS 16 Leases on January 1, 2019 using the modified retrospective approach. At December 31, 2018, the
Company did not report any finance leases in accordance with its previous accounting policy for leases.
Lease Obligations
Baytex had the following future commitments associated with its lease obligations at December 31, 2019.
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, 2019
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 $0.6 million and recorded lease payments of $6.0
million for the year ended December 31, 2019.
10. BANK LOAN
Bank loan - U.S. dollar denominated(1)
Bank loan - Canadian dollar denominated
Bank loan - principal(2)
Unamortized debt issuance costs
Bank loan
December 31, 2019
December 31, 2018
$
$
$
206,144 $
300,327
506,471 $
(1,059)
505,412 $
122,388
399,906
522,294
(1,594)
520,700
(1) U.S. dollar denominated bank loan balance was US$159.0 million as at December 31, 2019 (US$89.7 million as at December 31, 2018).
(2) The decrease in the principal amount of the bank loan outstanding from December 31, 2018 to December 31, 2019 is the result of loan
repayments of $7.1 million and changes in the reported amount of U.S. denominated debt of $8.7 million.
Baytex has US$575 million of revolving secured credit facilities (the "Revolving Facilities") and a CAD$300 million non-revolving
secured term loan (the "Term Loan"). On May 2, 2019, Baytex amended its credit facilities to extend maturity from June 4, 2020
to April 2, 2021. On March 3, 2020, Baytex amended its credit facilities to extend maturity 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.
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 Term Loan is secured by the assets of Baytex's wholly-owned subsidiary, Baytex Energy Limited Partnership.
Baytex Energy Corp. 2019 Annual Report
65
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, plus applicable margins. In the event that Baytex breaches any of
the covenants under the credit facilities, Baytex may be required to repay, refinance or renegotiate the loan terms and may be
restricted from taking on further debt or paying dividends to shareholders.
At December 31, 2019, Baytex had $15.2 million of outstanding letters of credit under the credit facilities (December 31, 2018 -
$14.6 million).
At December 31, 2019, Baytex was in compliance with all of the covenants contained in the credit facilities. The following table
summarizes the financial covenants applicable to the Revolving Facilities and Baytex's compliance therewith as at December 31,
2019.
Covenant Description
Senior Secured Debt(1) to Bank EBITDA(2) (Maximum Ratio)
Interest Coverage(3) (Minimum Ratio)
Position as at
December 31, 2019
0.52:1.00
9.42:1.00
Covenant
3.50:1.00
2.00:1.00
(1)
"Senior Secured Debt" is defined as the principal amount of the bank loan and other secured obligations identified in the credit agreement.
As at December 31, 2019, the Company's Senior Secured Debt totaled $521.7 million which includes $506.5 million of principal amounts
outstanding and $15.2 million of letters of credit.
(2) 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, 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, 2019 was $1,011.9 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, 2019 were $107.4 million.
(3)
11. LONG-TERM NOTES
6.75% notes (US$150,000 – principal) due February 17, 2021
5.125% notes (US$400,000 – principal) due June 1, 2021
6.625% notes (Cdn$300,000 – principal) due July 19, 2022
5.625% notes (US$400,000 – principal) due June 1, 2024
Total long-term notes - principal(1)
Unamortized debt issuance costs
Total long-term notes - net of unamortized debt issuance costs
December 31, 2019
December 31, 2018
$
$
$
— $
518,600
300,000
518,600
1,337,200 $
(9,025)
1,328,175 $
204,683
545,820
300,000
545,820
1,596,323
(13,083)
1,583,240
(1) The decrease in the principal amount of long-term notes outstanding from December 31, 2018 to December 31, 2019 is the result of
principal repayments of $198.1 million and changes in the reported amount of U.S. denominated debt of $61.0 million.
On September 13, 2019, Baytex completed the early redemption of the US$150,000 principal amount of 6.75% senior unsecured
notes, due February 17, 2021. The total principal payment was $198.1 million.
The long-term notes do not contain any significant financial maintenance covenants. The long-term notes contain a debt
incurrence covenant that restricts the Company's ability to raise additional debt beyond the existing credit facilities and long-term
notes unless the Company maintains a minimum coverage ratio (computed as the ratio of Bank EBITDA (as defined in note 10)
to financing and interest expense on a trailing twelve month basis) of 2.50:1.00. As at December 31, 2019, the fixed charge
coverage ratio was 8.04:1.00.
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 in arrears (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 $12.4 million were incurred in conjunction with the issuance which
resulted in net proceeds of $652.3 million.
On February 20, 2020, Baytex used a portion of the net proceeds from the issuance of the 8.75% Senior Notes of $652.3 million
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. On February 5, 2020, the Company also issued a notice of redemption for the $300 million
66
Baytex Energy Corp. 2019 Annual Report
principal amount of our 6.625% senior unsecured notes due July 19, 2022. Baytex expects to complete the early redemption of
these notes on March 6, 2020 at 101.104% of the principal amount plus accrued interest.
12. ASSET RETIREMENT OBLIGATIONS
Balance, beginning of year
Liabilities incurred
Liabilities settled
Liabilities assumed from corporate acquisition (note 4)
Liabilities acquired from property acquisitions
Liabilities divested
Property swaps
Accretion (note 18)
Change in estimate(1)
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, 2019
December 31, 2018
$
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 $
$
$
368,995
12,537
(14,035)
39,960
132
(580)
—
10,914
33,453
192,672
2,850
646,898
—
646,898
(1) 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, 2019, the undiscounted amount of estimated cash flows required to settle the asset retirement obligations is
$714.8 million (December 31, 2018 - $673.1 million). The discounted amount of estimated cash flow required to settle the asset
retirement obligations at December 31, 2019 calculated using an estimated inflation rate of 1.4% (December 31, 2018 - 2.0%)
and a risk free rate discount rate of 1.8% (December 31, 2018 - 2.2%) is $668.0 million (December 31, 2018 - $646.9 million).
These costs are expected to be incurred over the next 60 years.
13. 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, 2019, 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, 2017
Vesting of share awards
Issued on corporate acquisition (note 4)
Issuance costs, net of tax (note 4)
Balance, December 31, 2018
Vesting of share awards
Balance, December 31, 2019
Number of
Common Shares
(000s)
235,451 $
3,343
315,266
—
554,060 $
4,245
558,305 $
Amount
4,443,576
19,496
1,238,995
(551)
5,701,516
17,319
5,718,835
Baytex Energy Corp. 2019 Annual Report
67
14. SHARE-BASED COMPENSATION PLAN
The Company recorded compensation expense related to the share awards and share options of $15.9 million for the year
ended December 31, 2019 ($19.5 million for the year ended December 31, 2018).
Share Awards
The weighted average fair value of share awards granted during the year ended December 31, 2019 was $2.63 per restricted
and performance award (December 31, 2018 - $4.04).
The number of share awards outstanding is detailed below:
(000s)
Balance, December 31, 2017
Granted
Assumed on corporate acquisition (2)
Vested and converted to common shares
Forfeited
Balance, December 31, 2018
Granted
Vested and converted to common shares
Forfeited
Balance, December 31, 2019
Number of
restricted
awards
Number of
performance
awards(1)
Total number of
share awards
2,028
2,793
302
(1,682)
(198)
3,243
3,184
(2,081)
(545)
3,801
2,253
2,591
257
(1,661)
(167)
3,273
3,245
(2,164)
(1,219)
3,135
4,281
5,384
559
(3,343)
(365)
6,516
6,429
(4,245)
(1,764)
6,936
(1) Based on underlying awards before applying the payout multiplier which can range from 0x to 2x.
(2) Following closing of the business combination (note 4), holders of 0.3 million Raging River restricted awards and 0.3 million performance
awards are entitled to receive Baytex common shares rather than Raging River common shares, after adjusting the quantity of awards
outstanding based on the exchange ratio. The payout multiplier for the performance awards is fixed at 1.0. The fair value assigned to the
service period that had occurred prior to closing was included in consideration for the business combination.
Share Options
Baytex assumed share option plans pursuant to a business combination in 2018 (note 4). No new grants will be made under the
option plans.
The Company accounts for share options using the fair value method. Under this method, compensation is expensed over the
vesting period for the share options, with a corresponding increase in contributed surplus.
One third of the options granted will vest on each of the first, second, and third anniversaries of the date of grant. At December
31, 2019, 2.5 million share options with a weighted average exercise price of $6.83 were outstanding. The following tables
summarize the information about the share options.
(000s, except per common share amounts)
Balance, December 31, 2017
Assumed on corporate acquisition
Forfeited/Expired
Balance, December 31, 2018
Forfeited/Expired
Balance, December 31, 2019
Number of options
Weighted average
exercise price
— $
9,187
(4,322)
4,865 $
(2,390)
2,475 $
—
6.63
6.57
6.70
6.56
6.83
68
Baytex Energy Corp. 2019 Annual Report
Options Outstanding
Options Exercisable
Number
outstanding at
December 31,
2019 (000s)
1,654
821
2,475
Weighted
average
remaining life
(years)
Weighted
average
exercise price
Number
exercisable at
December 31,
2019 (000s)
Weighted
average
exercise price
0.79 $
0.15
0.58 $
6.39
7.73
6.83
1,248 $
821
2,069 $
6.42
7.73
6.94
Exercise price
$5.00 - $7.00
$7.01 - $9.00
Total
15. 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 exercised. The treasury stock method is used to determine the
dilutive effect of share awards and share options whereby the proceeds from the potential exercise of share options and the
amount of unrecognized share-based compensation expense on all share awards and share options, if any, attributed to future
services are assumed to be used to purchase common shares at the average market price during the year.
Years Ended December 31
2019
Weighted
average
common
shares
(000's)
Net loss
Net loss per
share
Net loss
2018
Weighted
average
common
shares
(000's)
Net loss per
share
Net loss - basic
$
(12,459)
557,048 $
(0.02) $
(325,309)
351,542 $
(0.93)
Dilutive effect of share awards
Dilutive effect of share options
—
—
—
—
—
—
—
—
—
—
—
—
Net loss - diluted
$
(12,459)
557,048 $
(0.02) $
(325,309)
351,542 $
(0.93)
For the year ended December 31, 2019, 6.9 million share awards (2018 - 6.5 million) and 2.5 million share options (2018 -
4.9 million) were excluded from the calculation of diluted earnings per share as the Company recorded a net loss.
16. 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
2019
2018
Canada
U.S.
Total
Canada
U.S.
Total
Light oil and condensate
$
538,487 $
600,163 $ 1,138,650 $
169,335 $
637,055 $
806,390
Heavy oil
NGL
Natural gas sales
500,187
8,430
30,620
—
500,187
411,794
60,647
67,385
69,077
98,005
14,531
23,555
—
97,008
75,592
411,794
111,539
99,147
Total petroleum and natural gas sales
$ 1,077,724 $
728,195 $ 1,805,919 $
619,215 $
809,655 $ 1,428,870
Included in accounts receivable at December 31, 2019 is $138.0 million (December 31, 2018 - $77.4 million) of accrued
petroleum and natural gas sales related to deliveries for periods ended prior to the reporting date.
Baytex Energy Corp. 2019 Annual Report
69
17.
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 26.72% (2018 – 27.00%)
(Increase) decrease in income tax recovery resulting from:
Share-based compensation
Non-taxable portion of foreign exchange (gain) loss
Effect of change in income tax rates
Effect of rate adjustments for foreign jurisdictions
Effect of change in deferred tax benefit not recognized(1)
Adjustments and assessments
Income tax recovery
Years Ended December 31
2019
(78,921) $
(21,088)
4,247
(8,155)
(6,098)
(27,785)
(7,563)
(20)
2018
(427,076)
(115,311)
5,185
14,467
—
(22,119)
14,467
1,544
(101,767)
$
(66,462) $
(1) A deferred income tax asset has not been recognized for accumulated allowable capital losses of $109 million ($139 million as at December
31, 2018) related to the foreign exchange losses arising from the translation of U.S. dollar denominated long-term notes.
For the year ended December 31, 2019, the deferred tax recovery includes $6.1 million attributable to decreases in the Alberta
provincial income tax rate for the period from July 1, 2019 to January 1, 2022, which reduced the provincial tax rate to 11%
effective July 1, 2019, and further reduces it by 1% on January 1st for each of the years 2020, 2021, and 2022, resulting in a
provincial rate of 8%.
In June 2016, certain indirect subsidiary entities received reassessments from the Canada Revenue Agency (the "CRA”) that
deny $591 million of non-capital loss deductions relevant 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 Office was assigned to the Company's file in July 2018. Baytex
remains confident that the original tax filings are correct and intends to defend these tax filings through the appeals process.
A continuity of the net deferred income tax liability is detailed in the following tables:
As at
Taxable temporary differences:
Petroleum and natural gas properties
Financial derivatives
Other
Deductible temporary differences:
Asset retirement obligations
Financial derivatives
Non-capital losses
Finance costs
January 1,
2019
Recognized
in Net
Income
Foreign
Currency
Translation
Adjustment
December
31, 2019
$
(954,506) $
48,995 $
23,517 $
(881,994)
(21,486)
(3,045)
21,486
5,192
—
—
(4,550)
(2,403)
172,359
(7,364)
—
802
(472)
—
399,699
96,143
(1,460)
(11,522)
904
—
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 2029 to 2039.
70
Baytex Energy Corp. 2019 Annual Report
As at
Taxable temporary differences:
January 1,
2018
Recognized
in Net Loss
Share
Issuance
Costs
Business
Combination
Foreign
Currency
Translation
Adjustment
December
31, 2018
Petroleum and natural gas properties
$
(696,427) $
(11,639) $
— $
(207,337) $
(39,103) $
(954,506)
Financial derivatives
Deferred income
Other
Deductible temporary differences:
Asset retirement obligations
Financial derivatives
Non-capital losses
Finance costs
—
(22,984)
(17,827)
(5,956)
97,977
8,528
330,749
78,258
17,827
(2,538)
62,984
(8,528)
48,725
17,885
—
—
209
—
—
—
—
1,498
—
—
10,789
—
—
—
—
—
(21,486)
—
5,240
(3,045)
609
—
20,225
—
172,359
—
399,699
96,143
Net deferred income tax liability(1)
$
(204,698) $
101,732 $
209 $
(195,050) $
(13,029) $
(310,836)
(1) Non-capital loss carry-forwards at December 31, 2018 totaled $1,733.8 million and expire from 2029 to 2038.
18. FINANCING AND INTEREST
Interest on bank loan
Interest on long-term notes
Interest on lease obligations
Non-cash financing
Accretion of asset retirement obligations (note 12)
Financing and interest
19. FOREIGN EXCHANGE
Unrealized foreign exchange (gain) loss
Realized foreign exchange loss
Foreign exchange (gain) loss
20. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
Years Ended December 31
2019
20,376 $
86,431
610
4,735
13,713
125,865 $
Years Ended December 31
2019
(62,753) $
966
(61,787) $
2018
15,637
88,681
—
3,854
10,914
119,086
2018
106,143
2,151
108,294
$
$
$
$
The Company's financial assets and liabilities are comprised of cash, trade and other receivables, trade and other payables,
financial derivatives, bank loan, long-term notes, and lease obligations. The fair value of the bank loan 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.
Baytex Energy Corp. 2019 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, 2019
December 31, 2018
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
Trade and other payables
Bank loan
Long-term notes
Lease obligations
Total
$
$
$
$
$
$
$
5,433 $
5,433 $
5,433 $
5,433 $
79,582 $
79,582 $
79,582
79,582
Level 2
5,572 $
5,572 $
— $
173,762
173,762
111,564
179,334 $
179,334 $
111,564 $
—
111,564
111,564
—
—
(8,668) $
(8,668) $
(8,668) $
(8,668) $
— $
— $
—
—
Level 2
(207,454) $
(207,454) $
(258,114) $
(258,114)
(505,412)
(506,471)
(520,700)
(522,294)
(1,328,175)
(1,290,817)
(1,583,240)
(1,492,363)
(13,883)
(13,883)
—
—
—
—
Level 1
—
$
(2,054,924) $
(2,018,625) $
(2,362,054) $
(2,272,771)
There were no transfers of financial instruments between Level 1 and Level 2 in during the years ended December 31, 2019 or
2018.
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 bank loan and long-term
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, 2019 and 2018, 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 $8.3 million.
72
Baytex Energy Corp. 2019 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$8,733
US$80,857
US$841,961
US$963,351
Assets
Liabilities
December 31, 2019
December 31, 2018
December 31, 2019
December 31, 2018
Interest Rate Risk
The Company's interest rate risk arises from borrowing at floating rates under the Revolving Facilities and Term Loan (note 10).
Based on the Company's principal bank loan outstanding net of the interest rate swap, as at December 31, 2019, a change of
100 basis points in interest rates would have an impact on net income or loss before income taxes of approximately $4.1 million.
Interest Rate Swaps
The Company mitigates its exposure to interest rate risk by entering into interest rate swap transactions. As of March 3, 2020,
Baytex had an interest rate swap outstanding with a notional value of $100 million maturing in October 2020, with a fixed contract
price of 2.02% referencing the Canadian Dollar Offered Rate. At December 31, 2019, the interest rate swap had a fair value of
zero (December 31, 2018 - $0.3 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, 2019, a US$1.00/bbl change in the underlying benchmark crude oil prices would impact net income or loss before
income taxes by approximately $17.5 million.
When assessing the potential
impact of natural gas price changes on the financial derivative contracts outstanding as at
December 31, 2019, a $0.25 change in the underlying benchmark natural gas prices would impact net income or loss before
income taxes by approximately $1.2 million.
Baytex Energy Corp. 2019 Annual Report
73
Financial Derivative Contracts
Baytex had the following financial derivative contracts outstanding as of March 3, 2020:
Oil
Basis swap
Basis swap (6)
Basis swap
Basis swap (6)
Fixed - Sell
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)
3-way option (2)
3-way option (2)
3-way option (2)
3-way option (2)
3-way option (2)
3-way option (2)
3-way option (2)
Swaption (3)
Swaption (4)
Swaption (4)
Natural Gas
3-way option (2)
Swaption (5)
Remaining Period
Volume
Price/Unit (1)
Index
Jan 2020 to Dec 2020
Apr 2020 to Dec 2020
Jan 2020 to Dec 2020
Apr 2020 to Dec 2020
Jan 2020 to Mar 2020
Jan 2020 to Dec 2020
Jan 2020 to Dec 2020
Jan 2020 to Dec 2020
Jan 2020 to Dec 2020
Jan 2020 to Dec 2020
Jan 2020 to Dec 2020
Jan 2020 to Dec 2020
Jan 2020 to Dec 2020
Jan 2020 to Dec 2020
Jan 2020 to Dec 2020
Jan 2020 to Dec 2020
Jan 2020 to Dec 2020
Jan 2020 to Dec 2020
Jan 2020 to Dec 2020
Jan 2021 to Dec 2021
Jan 2021 to Dec 2021
Jan 2021 to Dec 2021
2,500 bbl/d
4,000 bbl/d
2,000 bbl/d
3,000 bbl/d
6,000 bbl/d
2,000 bbl/d
3,000 bbl/d
3,000 bbl/d
4,500 bbl/d
3,000 bbl/d
1,000 bbl/d
1,000 bbl/d
1,500 bbl/d
1,500 bbl/d
1,000 bbl/d
1,000 bbl/d
1,000 bbl/d
1,000 bbl/d
2,000 bbl/d
3,000 bbl/d
3,000 bbl/d
3,000 bbl/d
WCS
WTI less US$16.10/bbl
WCS
WTI less US$16.38/bbl
MSW
WTI less US$6.50/bbl
MSW
WTI less US$5.92/bbl
WTI
US$56.60/bbl
US$58.00/bbl
WTI
US$50.00/US$56.00/US$61.35 WTI
US$50.00/US$57.00/US$60.00 WTI
US$50.00/US$57.00/US$62.00 WTI
US$50.00/US$58.00/US$62.00 WTI
US$51.00/US$58.00/US$60.50 WTI
US$51.00/US$58.00/US$60.83 WTI
US$51.00/US$59.00/US$65.60 WTI
US$51.00/US$59.00/US$66.00 WTI
US$51.00/US$59.50/US$66.15 WTI
US$51.00/US$60.00/US$65.60 WTI
US$51.00/US$60.00/US$66.00 WTI
US$51.00/US$60.00/US$66.05 WTI
US$51.00/US$60.00/US$66.70 WTI
US$64.50/bbl
US$70.00/bbl
US$60.75/bbl
Brent
Brent
WTI
Jan 2020 to Dec 2020
Jan 2021 to Dec 2021
5,000 mmbtu/d
5,000 mmbtu/d
US$2.25/US$2.60/US$2.85
US$2.90/mmbtu
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 US50 /US$58.00/US$62.00 contract, Baytex
receives WTI plus US$8.00/bbl when WTI is at or below US$50.00/bbl; Baytex receives US$58.00/bbl when WTI is between US$50.00/
bbl and US$58.00/bbl; Baytex receives the market price when WTI is between US$58.00/bbl and US$62.00/bbl; and Baytex receives US
$62.00/bbl when WTI is above US$62.00/bbl.
(3) For these contracts, the counterparty has the right, if exercised on September 30, 2020, to enter a swap transaction for the remaining term,
notional volume and fixed price per unit indicated above.
(4) For these contracts, the counterparty has the right, if exercised on December 31, 2020, to enter a swap transaction for the remaining term,
notional volume and fixed price per unit indicated above.
(5) For these contracts, the counterparty has the right, if exercised on December 23, 2020, to enter a swap transaction for the remaining term,
notional volume and fixed price per unit indicated above.
(6) Contracts entered subsequent to December 31, 2019.
The following table sets forth the realized and unrealized gains and losses recorded on financial derivatives.
Realized financial derivatives (gain) loss
Unrealized financial derivatives loss (gain)
Financial derivatives loss (gain)
Years Ended December 31
2019
(75,620) $
82,817
7,197 $
2018
73,165
(116,715)
(43,550)
$
$
74
Baytex Energy Corp. 2019 Annual Report
Liquidity Risk
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, 2019, Baytex had available
unused bank credit facilities in the amount of $523.8 million (December 31, 2018 - $547.7 million). In the event the Company is
not able to comply with the financial covenants contained in agreements with its lenders, the Company's ability to access
additional debt may be restricted.
The timing of cash outflows relating to financial liabilities as at December 31, 2019 is outlined in the table below:
Trade and other payables
Bank loan (1)(2)
Long-term notes (2)
Interest on long-term notes (3)
Lease obligations
Total
Less than
1 year
1-3 years
3-5 years Beyond 5 years
$
207,454 $
207,454 $
— $
506,471
1,337,200
217,247
14,568
—
—
75,625
6,216
506,471
818,600
100,303
7,748
— $
—
518,600
41,319
604
$
2,282,940 $
289,295 $
1,433,122 $
560,523 $
—
—
—
—
—
—
(1) At December 31, 2019, the bank loan was set to mature on April 2, 2021. On March 3, 2020, Baytex amended the bank loan 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 and issued a redemption notice for the $300 million principal amount of 6.625% senior unsecured notes due 2022 (note 11). The
Company expects to complete the redemption of these notes on March 6, 2020. On February 20, 2020 Baytex completed the redemption of
the US$400 million principal amount of senior unsecured notes due 2021 (note 11).
(3) Excludes interest on bank loan as interest payments on bank loans fluctuate based on amounts outstanding and interest rates.
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,
2019, the Company is exposed to credit risk with respect to its trade and other receivables and financial derivatives.
Credit risk is considered very low for the Company's trade and other receivables and financial derivatives due to the external
credit ratings of its counterparties and Baytex's process for selecting and monitoring credit-worthy counterparties. Most of the
Company's trade and other receivables relate to petroleum and natural gas sales and are exposed to typical industry credit risks.
Baytex reviews its exposure to individual entities on a regular basis and manages its credit risk by entering into sales contracts
with only creditworthy entities. 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 accounts receivable at December 31, 2019 relates to accrued revenues for
November and December 2019. 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 accounts receivable at December 31, 2019 is $138.0 million (December 31,
2018 - $77.4 million) of accrued petroleum and natural gas sales related to deliveries for periods ended prior to the reporting
date.
Should the Company determine that the ultimate collection of a receivable is in doubt, the carrying amount of accounts
receivable is reduced by the use of an 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, 2019, allowance for doubtful accounts was $1.6 million (December 31, 2018 - $1.9
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, 2019, accounts receivable that Baytex
has deemed past due (more than 90 days) but not impaired was $2.7 million (December 31, 2018 - $2.6 million). Baytex has
estimated the lifetime expected credit loss as at and for the years ended December 31, 2019 to be nominal.
Baytex Energy Corp. 2019 Annual Report
75
The Company's trade and other receivables, net of the allowance for doubtful accounts, were aged as follows at December 31,
2019.
Trade and Other Receivables Aging
Current (less than 30 days)
31-60 days
61-90 days
Past due (more than 90 days)
21. SUPPLEMENTAL INFORMATION
Change in Non-Cash Working Capital Items
Trade and other receivables
Trade and other payables
Non-cash working capital acquired (note 4)
Changes in non-cash working capital related to:
Operating activities
Investing activities
Foreign currency translation on non-cash working capital
Income Statement Presentation
December 31, 2019
December 31, 2018
169,500 $
104,099
1,199
342
2,721
3,037
1,842
2,586
173,762 $
111,564
Years Ended December 31
2019
(62,198) $
(50,660)
—
(112,858) $
(52,070) $
(62,485)
1,697
(112,858) $
2018
1,280
113,572
(46,773)
68,079
39,448
32,435
(3,804)
68,079
$
$
$
$
$
$
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
22. COMMITMENTS AND CONTINGENCIES
Years Ended December 31
2019
12,918 $
33,728
46,646 $
2018
12,140
34,963
47,103
$
$
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, 2019, and the expected timing of funding
of these obligations, are noted in the table below.
Processing agreements
Transportation agreements
Total
39,352
115,999
Less than
1 year
10,234
11,636
1-3 years
3-5 years Beyond 5 years
10,591
41,263
8,848
37,099
9,679
26,001
35,680
Total
$
155,351 $
21,870 $
51,854 $
45,947 $
76
Baytex Energy Corp. 2019 Annual Report
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.
23. RELATED PARTIES
Balances and transactions between the Company and its subsidiaries, which are related parties of the Company, have been
eliminated on consolidation and are not disclosed separately in this note.
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
24. CAPITAL MANAGEMENT
Years Ended December 31
2019
6,202 $
9,188
2,208
17,598 $
2018
8,703
10,985
3,025
22,713
$
$
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, 2019, the Company's capital structure was comprised of
shareholders' capital, long-term debt, working capital and the bank loan.
Baytex monitors its estimated adjusted funds flow and the level of undrawn credit facilities. 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, 2019, Baytex was in compliance with all of the covenants contained in the credit facilities and had unused
capacity of $523.8 million (December 31, 2018 - $547.7 million).
future dividends. Baytex eliminates changes in non-cash working capital,
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 capital investments, debt repayment, settlement of abandonment obligations and
potential
transaction costs, and 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. Transaction costs associated with business combinations (note 4) are excluded from adjusted funds
flow as the costs are considered non-recurring and not reflective of the Company's ability to generate adjusted funds flow on an
ongoing 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
Transaction costs
Adjusted funds flow
Years Ended December 31
2019
834,939 $
52,070
15,417
—
902,426 $
2018
485,322
(39,448)
14,035
13,074
472,983
$
$
Baytex Energy Corp. 2019 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 bank loan and long-term notes
outstanding, net of working capital. The current portion of financial derivatives is excluded as the valuation of the underlying
contracts is subject to a high degree of volatility prior to the ultimate settlement. Onerous contracts are excluded from net debt as
the underlying contracts do not represent an available source of liquidity. The principal amounts of the bank loan and long-term
notes outstanding are used in the calculation of net debt as these amounts represent the Company's ultimate repayment
obligation at maturity. The carrying amount of debt issue costs associated with the bank loan 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 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.
Bank loan - principal
Long-term notes - principal
Trade and other payables
Cash
Trade and other receivables
Net debt
December 31, 2019
December 31, 2018
$
$
506,471 $
1,337,200
207,454
(5,572)
(173,762)
1,871,791 $
522,294
1,596,323
258,114
—
(111,564)
2,265,167
78
Baytex Energy Corp. 2019 Annual Report
PETROLEUM AND NATURAL GAS RESERVES AS AT DECEMBER 31, 2019
Baytex's year-end 2019 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, 2020. Reserves associated with our thermal
heavy oil projects at Peace River, 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, 2019, which will
be filed on or before March 30, 2020.
The following table sets forth our gross and net reserves volumes at December 31, 2019 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
Light and
Medium Oil
(mbbls)
Tight Oil
(mbbls)
Heavy
Oil
(mbbls)
Bitumen
(mbbls)
Total Oil
(mbbls)
27,297
—
33,322
60,619
31,218
91,837
25,447
—
31,052
56,499
28,703
85,201
23,273
39
32,250
55,562
24,139
79,701
17,245
29
24,029
41,303
18,214
59,517
28,050
570
22,691
51,311
37,805
89,116
24,818
483
20,371
45,672
32,813
78,486
2,711
7,196
1,892
11,799
53,743
65,542
2,504
6,766
1,873
11,144
43,031
54,175
81,331
7,805
90,155
179,291
146,905
326,196
70,015
7,278
77,325
154,618
122,761
277,379
Natural
Gas
Liquids (3)
(mbbls)
34,218
388
43,333
77,939
35,654
Conventional
Natural Gas (4)
(mmcf)
Shale
Gas
(mmcf)
56,743
2,492
45,272
104,506
99,816
99,628
1,018
133,516
234,162
99,739
Total (5)
(mboe)
141,611
8,778
163,286
313,674
215,818
113,592
204,323
333,901
529,492
25,470
287
32,206
57,963
26,797
84,760
53,003
2,022
40,444
95,469
90,061
74,009
757
99,106
173,872
74,952
116,654
8,029
132,789
257,471
177,060
185,530
248,823
434,531
Notes:
(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. 2019 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, 2018
Product Type Transfer (2)
Extensions
Technical Revisions (3)
Acquisitions
Dispositions
Economic Factors
Production
December 31, 2019
Light and
Medium Oil
(mbbls)
71,545
—
7,328
(9,133)
1,264
(2,347)
(217)
(7,822)
Tight Oil
(mbbls)
52,819
—
7,510
1,865
—
—
(1,232)
(5,401)
Heavy
Oil Bitumen
(mbbls)
12,805
—
—
(341)
—
—
118
(784)
(mbbls)
49,613
—
4,845
9,012
18
—
(3,201)
(8,977)
Total Oil
(mbbls)
186,783
—
19,683
1,403
1,282
(2,347)
(4,531)
(22,983)
Natural
Gas
Liquids (4)
(mbbls)
74,614
—
8,260
2,109
2
—
(625)
(6,421)
Conventional
Natural Gas (5)
(mmcf)
168,104
(57,548)
6,225
8,463
227
(90)
(3,590)
(17,285)
Shale
Gas
(mmcf)
151,156
57,548
26,200
21,868
—
—
(2,393)
(20,216)
60,619
55,562
51,311
11,799
179,291
77,939
104,506
234,162
Probable Reserves – Gross Volumes (1) (Forecast Prices)
December 31, 2018
Product Type Transfer (2)
Extensions
Technical Revisions (3)
Acquisitions
Dispositions
Economic Factors
Production
December 31, 2019
Light and
Medium Oil
(mbbls)
20,941
—
8,761
1,696
416
(579)
(17)
—
31,218
Tight Oil
(mbbls)
21,879
—
2,877
768
—
—
(1,385)
—
24,139
Heavy
Oil Bitumen
(mbbls)
55,545
—
—
(1,887)
—
—
85
—
53,743
(mbbls)
42,687
—
(363)
(4,317)
5
—
(207)
—
37,805
Proved Plus Probable Reserves – Gross Volumes (1) (Forecast Prices)
Light and
Medium Oil
(mbbls)
92,487
—
16,089
(7,437)
1,680
(2,926)
(234)
(7,822)
Tight Oil
(mbbls)
74,698
—
10,387
2,634
—
—
(2,616)
(5,401)
Heavy
Oil Bitumen
(mbbls)
68,350
—
—
(2,228)
—
—
204
(784)
(mbbls)
92,301
—
4,482
4,695
23
—
(3,408)
(8,977)
December 31, 2018
Product Type Transfer (2)
Extensions
Technical Revisions (3)
Acquisitions
Dispositions
Economic Factors
Production
December 31, 2019
Notes:
Natural
Gas
Liquids (4)
(mbbls)
38,473
—
63
(1,590)
1
—
(1,293)
—
35,654
Natural
Gas
Liquids (4)
(mbbls)
113,087
—
8,323
518
3
—
(1,919)
(6,421)
Conventional
Natural Gas (5)
(mmcf)
122,685
(24,653)
(473)
2,822
82
(27)
(619)
—
99,816
Conventional
Natural Gas (5)
(mmcf)
290,789
(82,200)
5,752
11,285
309
(118)
(4,209)
(17,285)
Total Oil
(mbbls)
141,052
—
11,275
(3,740)
420
(579)
(1,524)
—
146,905
Total Oil
(mbbls)
327,836
—
30,958
(2,337)
1,702
(2,926)
(6,054)
(22,983)
Shale
Gas
(mmcf)
71,550
24,653
2,504
5,923
—
—
(4,890)
—
99,739
Shale
Gas
(mmcf)
222,706
82,200
28,703
27,790
—
—
(7,283)
(20,216)
Total (6)
(mboe)
314,607
—
33,347
8,567
1,322
(2,362)
(6,153)
(35,653)
313,674
Total (6)
(mboe)
211,898
—
11,676
(3,873)
435
(583)
(3,735)
—
215,818
Total (6)
(mboe)
526,505
—
45,023
4,695
1,757
(2,945)
(9,888)
(35,653)
91,837
79,701
89,116
65,542
326,196
113,592
204,323
333,901
529,492
(1)
“Gross” reserves means the total working interest share of remaining recoverable reserves owned by Baytex before deductions of royalties payable to others.
(2) Product type transfer reflects the reclassification of solution gas in the Eagle Ford from conventional natural gas to shale gas.
(3) Positive technical revisions for heavy oil are largely the results of positive production performance versus previous forecasts in both our Lloydminster and Peace
River areas. Positive conventional natural gas revisions are predominately related to the solution gas associated with our heavy oil assets. Positive technical
revisions in the tight oil and shale gas are a result of enhanced type well profiles in our Eagle Ford acreage. Negative technical revisions in the light and medium
oil are associated with our Viking area and are predominately a result of a reduction in later life reserves associated with the production profile.
(4) Natural gas liquids include condensate.
(5) Conventional natural gas includes associated, non-associated and solution gas.
(6) 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. 2019 Annual Report
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)
2020
2021
2022
2023
2024
Remainder
Total FDC undiscounted
Proved
Reserves
530
522
563
444
496
2
2,558
Proved Plus
Probable Reserves
536
562
625
611
848
1,132
4,315
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)
2019
2018
2017
3 Year
$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
$326.3
($76.4)
34.4
$7.26
$386.1
$84.2
51.6
$9.11
$326.3
($132.6)
21.7
$8.93
$386.1
($97.1)
28.5
$10.13
$326.3
23.8
$13.73
$386.1
27.5
$14.06
$1,374.3
$152.7
105.5
$14.48
$3,040.2
$1,228.6
214.1
$19.94
$1,374.3
($105.6)
74.9
$16.93
$3,040.2
$783.1
151.7
$25.21
$1,374.3
97.4
$14.10
$3,040.2
133.7
$22.73
Baytex Energy Corp. 2019 Annual Report
81
Reserves Life Index
The following table sets forth our reserves life index, which is calculated by dividing our proved and proved plus probable reserves
at year-end 2019 by annualized Q4/2019 production.
Q4/2019
Production
79,655
100,234
96,360
Reserves Life Index (years)
Proved
8.8
9.3
8.9
Proved Plus
Probable
15.1
14.7
15.1
Crude Oil and NGL (bbl/d)
Natural Gas (mcf/d)
Oil Equivalent (boe/d)
Forecast Prices and Costs
The following table summarizes the forecast prices used in preparing the estimated reserves volumes and the net present values
of future net revenues at December 31, 2019. The estimated future net revenue to be derived from the production of the reserves
is based on the following average of the price forecasts of McDaniel, GLJ and Sproule as of January 1, 2020.
Year
2019 act.
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
WTI Crude Oil
US$/bbl
56.95
Edmonton Light
Crude Oil
$/bbl
68.65
61.00
63.75
66.18
67.91
69.48
71.07
72.68
74.24
75.73
77.24
72.64
76.06
78.35
80.71
82.64
84.60
86.57
88.49
90.31
92.17
Western
Canadian Select
$/bbl
58.10
57.57
62.35
64.33
66.23
67.97
69.72
71.49
73.20
74.80
76.43
Henry Hub
US$/MMbtu
2.55
AECO Spot
$/MMbtu
1.60
2.62
2.87
3.06
3.17
3.24
3.32
3.39
3.45
3.53
3.60
2.04
2.32
2.62
2.71
2.81
2.89
2.96
3.03
3.09
3.16
Thereafter
Escalation rate of 2.0%
Net Present Value of Reserves (1) (Forecast Prices and Costs)
Inflation Rate
%/Yr
Exchange Rate
$US/$Cdn
2.0
0.0
1.7
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
0.750
0.760
0.770
0.785
0.785
0.785
0.785
0.785
0.785
0.785
0.785
0.785
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, 2019 ($ millions, discounted at)
Proved developed producing
Proved developed non-producing
Proved undeveloped
Total proved
Probable
Total Proved Plus Probable (before tax)
Note:
0%
2,640
179
3,256
6,075
5,627
11,702
5%
2,501
118
2,096
4,714
3,029
7,743
10%
2,211
81
1,419
3,710
1,890
5,600
15%
1,965
57
991
3,013
1,298
4,310
(1)
Includes abandonment, decommissioning and reclamation costs for all producing and nonproducing wells and facilities.
82
Baytex Energy Corp. 2019 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, 2019.
($ 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%
7,743
162
(1,871)
6,034
10.81
10%
5,600
162
(1,871)
3,891
6.97
15%
4,310
162
(1,871)
2,601
4.66
(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 558.3 million common shares outstanding as at December 31, 2019.
Advisory Regarding Oil and Gas Information
The reserves information contained in this report have 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, 2019, which will be filed on or before
March 30, 2020. 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 press release 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.
This report contains metrics commonly used in the oil and natural gas industry, such as “capital efficiencies”, “finding and
development costs”, “finding, development and acquisition costs”, “net asset value”, “recycle ratio,” “operating netback,” 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 press
release 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.
Baytex Energy Corp. 2019 Annual Report
83
In 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 year ended
December 31, 2019. 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.
Light
and
Medium
Oil
(bbl/d)
Heavy
Oil
(bbl/d)
NGL
(bbl/d)
Natural
Gas
(Mcf/d)
Oil
Equivalent
(boe/d)
14,334
12,407
14
—
45
—
14,503
964
16,810
12,568
—
—
—
20,527
928
889
125
491
703
11,361
1,613
20,528
22,546
1,688
5,013
—
21,229
8,865
53,773
39,055
Canada - Heavy
Peace River
Lloydminster
Canada - Light
Viking
Duvernay
Remaining properties
United States
Eagle Ford
Total
26,741
43,587
10,229 102,742
97,680
Capital efficiency means the cost to drill, complete, equip and tie-in a well divided by the initial production rate of the well on a boe
basis over its initial 365 days of production.
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, 2019, plus the estimated value of our undeveloped land holdings,
less net debt.
Recycle ratio means operating netback divided by finding and development costs for the particular reserves category.
Reserve life index means the reserves for the particular reserve category divided by annualized 2019 fourth quarter production.
This report discloses drilling inventory and potential drilling locations. Drilling inventory and drilling locations refers to Baytex’s total
proved, probable and unbooked locations. Proved locations and probable locations account for drilling locations in our inventory
that have associated proved and/or probable reserves. Unbooked locations are internal estimates based on our prospective
acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review.
Unbooked locations do not have attributed reserves. Unbooked locations are farther away from existing wells and, therefore, there
is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty whether such wells will
result in additional oil and gas reserves, resources or production. In the Eagle Ford, Baytex’s net drilling locations include 140
proved and 83 probable locations as at December 31, 2019 and 52 unbooked locations. In the Viking, Baytex’s net drilling locations
include 1,080 proved and 319 probable locations as at December 31, 2019 and 636 unbooked locations. In Peace River, Baytex’s
net drilling locations include 77 proved and 75 probable locations as at December 31, 2019 and 100 unbooked locations. In
Lloydminster, Baytex’s net drilling locations include 178 proved and 63 probable locations as at December 31, 2019 and 361
unbooked locations. In the Duvernay, Baytex’s net drilling locations include 11 proved and 10 probable locations as at December
31, 2019 and 295 unbooked locations.
84
Baytex Energy Corp. 2019 Annual Report
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.
Baytex Energy Corp. 2019 Annual Report
85
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.
86
Baytex Energy Corp. 2019 Annual Report
Corporate
Information
BOARD OF
DIRECTORS
Mark R. Bly 2
Chairman of the Board
Edward D. LaFehr
Director
Trudy M. Curran 2,4
Director
Naveen Dargan 1,3
Director
Don G. Hrap 3
Director
Jennifer A. Maki 1,2
Director
Gregory K. Melchin 1,4
Director
David L. Pearce 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
OFFICERS
AUDITORS
KPMG LLP
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
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
Computershare Trust
Company of Canada
EXCHANGE LISTINGS
Toronto Stock Exchange
New York Stock Exchange
Symbol: BTE
Head Office
Baytex Energy Corp.
Centennial Place, East Tower
2800, 520 - 3rd Avenue SW
Toll-free 1.800.524.5521
T 587.952.3000
F 587.952.3001
Calgary, Alberta T2P 0R3
www.baytexenergy.com
Design: ARTHUR / HUNTER
Printing: Merrill Corporation
Symbol
BTE
W W W.B AY T E X E N E R G Y . C O M