A N N U A L
R E P O R T
CREATING ENERGY
CREATING VALUE
E
T
X B
S
E | T
S
Y
N
HIGHLIGHTS
Ranger Oil acquisition
adds quality scale
in the Eagle Ford
122,154 boe/d
for the full-year 2023
$ 544 million
of free cash flow
Increased shareholder returns to
50%
of free cash flow
Introduced
quarterly dividend of
$0.0225 cents per share
65%reduction
in GHG emissions intensity,
relative to our 2018 baseline
AB SK
Peace River / Peavine
Duvernay
Lloydminster
Viking
OUR
OPERATING
AREAS
TX
Eagle Ford
TABLE OF
CONTENTS
Summary
Reserves Information
Management’s Discussion and Analysis
Management’s Report
Auditors’ Reports
Consolidated Financial Statements
1
7
18
62
67
68
E
T
X B
S
E | T
S
Y
N
SUMMARY
FINANCIAL
(thousands of Canadian dollars, except per common share amounts)
Petroleum and natural gas sales
Adjusted funds flow (1)
Per share – basic
Per share – diluted
Free cash flow (2)
Per share – basic
Per share – diluted
Cash flows from operating activities
Per share – basic
Per share – diluted
Net income (loss)
Per share – basic
Per share – diluted
Dividends declared
Per share – basic
Capital Expenditures
Exploration and development expenditures
Acquisitions and (divestitures)
Total oil and natural gas capital expenditures
Net Debt
Credit facilities
Long-term notes
Long-term debt (3)
Working capital deficiency (2)
Net debt (1)
Shares Outstanding - basic (thousands)
Weighted average
End of period
BENCHMARK PRICES
Crude oil
WTI (US$/bbl)
MEH oil (US$/bbl)
MEH oil differential to WTI (US$/bbl)
Edmonton par ($/bbl)
Edmonton par differential to WTI (US$/bbl)
WCS heavy oil ($/bbl)
WCS differential to WTI (US$/bbl)
Natural gas
NYMEX (US$/mmbtu)
AECO ($/mcf)
CAD/USD average exchange rate
Twelve Months Ended
December 31, 2023
December 31, 2022
$
$
$
$
$
$
$
$
3,382,621
1,594,350
2.26
2.26
543,620
0.77
0.77
1,295,731
1.84
1.84
(233,356)
(0.33)
(0.33)
37,519
0.045
1,012,787
(121,342)
891,445
864,736
1,597,475
2,462,211
72,076
$
2,534,287
$
704,896
821,681
$
$
$
$
77.62
79.29
1.67
100.46
(3.18)
79.58
(18.65)
2.74
2.93
1.3495
2,889,045
1,165,151
2.09
2.07
621,526
1.11
1.10
1,172,872
2.10
2.08
855,605
1.53
1.52
–
–
521,542
(24,297)
497,245
385,394
554,597
939,991
47,455
987,446
557,986
544,930
94.23
97.79
3.57
119.95
(2.07)
98.94
(18.21)
6.64
5.56
1.3016
(1) Capital management measure. Refer to the Specified Financial Measures section in this press release for further information.
(2) Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar
measures presented by other entities. Refer to the Specified Financial Measures section in this press release for further information.
(3) Calculated in accordance with our amended credit facilities agreement which is available on SEDAR+ at www.sedarplus.com.
2023 / Annual Report / Baytex Energy
1
SUMMARY
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) (1)
Netback (thousands of Canadian dollars)
Total sales, net of blending and other expense (2)
Royalties
Operating expense
Transportation expense
Operating netback (2)
General and administrative
Cash financing and interest
Realized financial derivatives loss
Other (3)
Adjusted funds flow (4)
Netback per boe (2)
Total sales, net of blending and other expense (2)
Royalties (5)
Operating expense (5)
Transportation expense (5)
Operating netback (2)
General and administrative (5)
Cash financing and interest (5)
Realized financial derivatives loss (5)
Other (3)
Adjusted funds flow (4)
Twelve Months Ended
December 31, 2023
December 31, 2022
53,389
35,460
14,304
103,153
114,010
122,154
3,157,819
(669,792)
(570,839)
(89,306)
1,827,882
(69,789)
(159,823)
36,212
(40,132)
1,594,350
70.82
(15.02)
(12.80)
(2.00)
41.00
(1.57)
(3.58)
0.81
(0.90)
$
$
$
$
$
$
$
$
$
$
$
35.76
$
33,101
28,993
7,575
69,669
83,101
83,519
2,699,591
(562,964)
(422,666)
(48,561)
1,665,400
(50,270)
(80,386)
(334,481)
(35,112)
1,165,151
88.56
(18.47)
(13.86)
(1.59)
54.64
(1.65)
(2.64)
(10.97)
(1.16)
38.22
Notes:
(1) 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.
(2) Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation
of similar measures presented by other entities. Refer to the Specified Financial Measures section in this press release for further information.
(3) Other is comprised of realized foreign exchange gain or loss, other income or expense, current income tax expense or recovery and share-based
compensation. Refer to the 2023 MD&A for further information on these amounts.
(4) Capital management measure. Refer to the Specified Financial Measures section in this press release for further information.
(5) Calculated as royalties, operating, transportation expense, general and administrative expense, cash interest expense or realized financial derivatives
gain (loss) divided by barrels of oil equivalent production volume for the applicable period.
2
2023 / Annual Report / Baytex Energy
BAYTEX ANNOUNCES FOURTH QUARTER AND FULL YEAR 2023 FINANCIAL AND
OPERATING RESULTS AND YEAR END RESERVES
CALGARY, ALBERTA (February 28, 2024) - Baytex Energy Corp. ("Baytex")(TSX, NYSE: BTE) reports its operating and financial
results for the three months and year ended December 31, 2023 (all amounts are in Canadian dollars unless otherwise noted).
“Our 2023 results demonstrate the strength of our oil-weighted portfolio. The strategic acquisition of Ranger added quality scale in
the Eagle Ford and reinforced the resiliency and sustainability of our business. In 2023, we increased production per share by 16%
and fourth quarter production exceeded guidance with continued strong results in the Eagle Ford and Peavine. During 2023, we
increased shareholder returns to 50% of free cash flow, increased our share buyback program and introduced a quarterly dividend.
We are well-capitalized and remain committed to creating long-term value and increasing shareholder returns," commented Eric T.
Greager, President and Chief Executive Officer.
2023 Highlights
•
•
•
•
•
•
•
•
•
Completed the acquisition of Ranger Oil Corporation ("Ranger") on June 20, 2023.
Reported cash flows from operating activities of $474 million ($0.57 per basic share) in Q4/2023 and $1,296 million ($1.84
per basic share) for 2023.
Delivered adjusted funds flow(1) of $502 million ($0.60 per basic share) in Q4/2023 and $1,594 million ($2.26 per basic
share) for 2023.
Generated free cash flow(2) of $291 million ($0.35 per basic share) in Q4/2023 and $544 million ($0.77 per basic share) for
2023.
Increased direct shareholder returns to 50% of free cash flow(2) and returned $260 million to shareholders. Repurchased
40.5 million common shares for $222 million, representing 4.7% of our shares outstanding, and declared two quarterly
dividends of $0.0225 per share, totaling $38 million in 2023.
Increased production per basic share by 16% in 2023, compared to 2022. Production for the full-year 2023 averaged
122,154 boe/d (85% oil and NGL), compared to 83,519 boe/d in 2022 (84% oil and NGL).
Production in Q4/2023 averaged 160,373 boe/d (83% oil and NGL), exceeding guidance of 158,000 to 160,000 boe/d, and
up 6% from Q3/2023 on exploration and development expenditures of $199 million, 10% below guidance.
Divested of our Viking assets at Forgan and Plato in southwest Saskatchewan (production of approximately 4,000 boe/d)
for proceeds of $160 million, including closing adjustments.
Improved our cash cost structure (operating, transportation, and general & administrative expenses) in Q4/2023 by 12%
on a boe basis, as compared to Q4/2022.
• Maintained balance sheet strength with a total debt to EBITDA(3) ratio(2) of 1.1x. During the fourth quarter we reduced our
•
•
•
net debt(1) by 10% ($290 million).
Reduced our GHG emissions intensity in 2023 by 9% from 2022 levels and achieved our 65% reduction target, relative to
our 2018 baseline, two years early.
Proved developed producing reserves increased by 49%, from 124 MMboe to 185 MMboe(4). Proved reserves increased
by 55%, from 264 MMboe to 410 MMboe(4). Proved plus probable reserves increased by 51%, from 438 MMboe to 663
MMboe(4).
At year-end 2023, the present value of our 2P reserves, discounted at 10% before tax, is estimated to be $7.8 billion ($5.9
billion at year-end 2022).
We recorded a non-cash impairment of $834 million on our legacy non-operated Eagle Ford and retained Viking assets as the
carrying value of our oil and gas properties exceeded their recoverable amounts. This resulted in a net loss of $626 million ($0.75
per basic share) in Q4/2023 and $233 million ($0.33 per basic share) in 2023.
(1) Capital management measure. Refer to the Specified Financial Measures section in this press release for further information.
(2)
Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures
presented by other entities. Refer to the Specified Financial Measures section in this press release for further information.
(3) Calculated in accordance with our amended credit facilities agreement which is available on SEDAR+ at www.sedarplus.com.
(4)
Baytex's year-end 2023 reserves were evaluated by McDaniel & Associates Consultants Ltd. (“McDaniel”), an independent qualified reserves evaluator, in
accordance with National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” (“NI 51-101”).
2023 / Annual Report / Baytex Energy
3
Strategy and 2024 Outlook
We are a well-capitalized, North American oil-weighted producer with 60% of our producing assets located in the Eagle Ford with
the balance in western Canada. We are committed to a disciplined, returns-based capital allocation philosophy to drive increased
per-share returns. The key elements of our business strategy include:
•
•
•
Disciplined Capital Allocation. Each of our core assets has 10 or more years of development inventory at our planned
pace of development. This provides us the ability to efficiently allocate capital and respond to changes in regional
commodity prices and other economic factors. Over our five-year outlook (2024 to 2028), we expect to generate annual
production growth of 1% to 4%, with production reaching approximately 170,000 boe/d in 2028.
Free Cash Flow(1). Our commitment to disciplined capital allocation across our portfolio is expected to generate
meaningful free cash flow(1). We intend to allocate 50% of free cash flow(1) to debt repayment and 50% to shareholder
returns, which includes a combination of share buybacks and a quarterly dividend.
Financial Strength. We are committed to maintaining a strong balance sheet and significant financial liquidity. We are in a
strong financial position with a total debt to EBITDA(2) ratio(1) of 1.1x. Upon reaching a total debt(2) target of $1.5 billion, we
intend to direct 75% of free cash flow(1) to shareholder returns.
In January, extremely cold temperatures across North America, followed by heavy rainfall in Texas, led to production disruptions.
Our production has been restored, however, first quarter production will be approximately 2,000 boe/d lower than our budget
expectation. Despite this, our 2024 guidance remains unchanged with exploration and development expenditures of $1.2 to $1.3
billion and production of 150,000 to 156,000 boe/d. In 2024, we intend to progress the Pembina Duvernay, further delineate our
Clearwater and Mannville heavy oil positions, and deliver strong drilling and completion performance in the Eagle Ford and Viking.
Based on the forward strip(3), we expect to generate approximately $575 million of free cash flow(1) in 2024. Our capital program is
weighted to the first and third quarters and as a result, we expect to generate a significant amount of our 2024 free cash flow(1)
during the second and fourth quarters.
2023 Results
On June 20, 2023, we closed the acquisition of Ranger, adding quality scale in the Eagle Ford and reinforcing a resilient and
sustainable business. In conjunction with closing, we increased direct shareholder returns to 50% of free cash flow(1), which
allowed us to increase the value of our share buyback program and introduce a dividend. The remainder of our free cash flow(1)
was allocated to debt reduction.
In 2023, we returned $260 million to shareholders through our share buyback program and dividend. Our normal course issuer bid
allows for the purchase of up to 68.4 million common shares during the 12-month period ending June 28, 2024. Through December
31, 2023, we repurchased 40.5 million common shares for $222 million, representing 4.7% of our shares outstanding, at an
average price of $5.48 per share. In addition, we declared two quarterly dividends of $0.0225 per share, totaling $38 million.
We increased production per basic share by 16% in 2023, compared to 2022. Production in Q4/2023 averaged 160,373 boe/d
(83% oil and NGL), exceeding our guidance for the quarter of 158,000 to 160,000 boe/d, and up 6% from 150,600 boe/d (85% oil
and NGL) in Q3/2023. Production for the full-year 2023 averaged 122,154 boe/d, compared to 83,519 boe/d in 2022.
Exploration and development expenditures totaled $1,013 million in 2023 as compared to our annual guidance of $1,035 million.
We participated in the drilling of 303 (254.0 net) wells in 2023. For the second half of 2023, exploration and development
expenditures totaled $608 million, consistent with our plan following the Ranger acquisition.
Our business improved structurally through the Ranger acquisition with increased exposure to premium U.S. Gulf Coast pricing and
improved margins. In Q4/2023, over 40% of our liquids production received WTI equivalent pricing and our realized light oil and
condensate price in the Eagle Ford was $105.83/bbl, or US$77.60/bbl. In addition, we improved our cash cost structure (operating,
transportation, general & administrative expenses) in Q4/2023 by 12% on a boe basis compared to Q4/2022.
(1)
Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures
presented by other entities. Refer to the Specified Financial Measures section in this press release for further information.
(2) Calculated in accordance with our amended credit facilities agreement which is available on SEDAR+ at www.sedarplus.com.
(3)
2024 pricing assumptions: WTI - US$75/bbl; WCS differential - US$16/bbl; NYMEX Gas - US$2.25/MMbtu; and Exchange Rate (CAD/USD) - 1.35.
4
2023 / Annual Report / Baytex Energy
On December 11, 2023, we completed the divestiture of Viking assets at Forgan and Plato in southwest Saskatchewan for
proceeds of $160 million, including closing adjustments. Proceeds from the sale were applied against our credit facilities.
Production from the assets at the time of the sale was approximately 4,000 boe/d (100% light and medium crude oil). We incurred
a non-cash loss of $144 million related to the sale.
During the fourth quarter we reduced our net debt(1) by 10% ($290 million) due to a combination of free cash flow generation, net
proceeds from the Viking divestiture and the impact of a strengthening Canadian dollar, relative to the U.S. dollar, on our U.S. dollar
denominated debt. Our total debt(2) at December 31, 2023 was $2.5 billion and we have $588 million of undrawn capacity on our
credit facilities.
We employ a disciplined commodity hedging program to help mitigate the volatility in revenue due to changes in commodity prices.
In 2023, our hedging program generated realized financial derivatives gains of $36 million. For 2024, we have entered into hedges
on approximately 40% of our net crude oil exposure utilizing two-way collars with an average floor price of US$60/bbl and an
average ceiling price of US$96/bbl. A complete listing of our financial derivative contracts can be found in Note 18 to our 2023
financial statements.
At year-end 2023, we identified indicators of impairment on our legacy non-operated Eagle Ford and retained Viking assets. As a
result, we recorded total non-cash impairments of $834 million in Q4/2023 as the carrying value of our oil and gas properties
exceeded their recoverable amounts. This non-cash impairment resulted in a net loss of $626 million ($0.75 per basic share) in
Q4/2023 and $233 million ($0.33 per basic share) in 2023.
Operations
The integration of the Ranger assets has progressed well. We continue to optimize base performance and remain focused on
strong drilling and completion performance. For 2024, we are targeting an 8% improvement in our operated drilling and completion
costs per completed lateral foot over 2023.
In the Eagle Ford, we continue to deliver strong results across the black oil, volatile oil, and condensate thermal maturity windows.
In Q4/2023, 9 (8.9 net) operated wells were brought onstream, bringing the total operated wells on production since closing the
Ranger acquisition to 22 (21.8 net) wells. The nine wells brought onstream during the fourth quarter generated an average 30-day
initial production rate of approximately 1,600 boe/d (80% oil and NGL) per well. On our non-operated acreage, there were no new
wells brought onstream during the fourth quarter.
In the Pembina Duvernay, we commenced drilling operations in January and to-date have drilled three of seven wells planned for
2024. Completion activities are scheduled to commence in May. We continue to advance our understanding of the reservoir and
believe the asset offers significant economic inventory growth potential.
In our heavy oil business unit, our Clearwater production averaged 16,338 boe/d during the fourth quarter, up 48% from Q4/2022.
At Peavine, we brought 31 (31.0 net) wells onstream during 2023 and initial well performance continues to outperform type curve
assumptions. In 2024, we will see continued exploration across our heavy oil portfolio with up to 14 stratigraphic test wells planned.
Quarterly Dividend
The Board of Directors has declared a quarterly cash dividend of $0.0225 per share to be paid on April 1, 2024 for shareholders of
record on March 15, 2024.
(1) Capital management measure. Refer to the Specified Financial Measures section in this press release for further information.
(2) Calculated in accordance with our amended credit facilities agreement which is available on SEDAR+ at www.sedarplus.com.
2023 / Annual Report / Baytex Energy
5
Environmental Stewardship
The energy industry and society are undergoing an evolution toward lower carbon intensity, and we believe that oil and gas will be
instrumental in this energy evolution. As a responsible energy producer, we are committed to reducing greenhouse gas (“GHG”)
emissions from our operations, minimizing freshwater use, and reclaiming our assets at the end of their economic life.
GHG Emissions
We are committed to monitoring GHG emissions from our operations, setting targets to reduce our GHG emissions intensity, and
pursuing cost-effective strategies to produce energy for society with a lower carbon intensity. Our emissions reduction strategy
includes increased gas conservation and destruction, reusing associated gas as fuel for field activities, capturing and reducing
emissions from storage tanks, along with monitoring and preventing fugitive emissions.
Our corporate objective set in 2019 was to reduce our GHG emissions intensity (kg of CO2e per boe) by 65% by 2025 (set on our
Canadian assets), relative to our 2018 baseline. In 2023, we invested $12 million in GHG reduction capital, reduced our GHG
emissions intensity by 9% and achieved our 65% target two years early.
Continuous improvement is an important element of our corporate culture and we intend to set the bar higher. We are in the
process of road mapping 2030 GHG reduction targets. Further details will be available in our 2023 ESG Report to be released in
July 2024.
In 2024, we will invest approximately $18 million as part of our GHG mitigation program as we continue to invest in monitoring and
lowering GHG emissions from our operations.
GHG Emissions Intensity (Scope 1 and Scope 2)(1) - Segment Canada
kg CO2e/boe
Water Management
2018
Baseline
122
2019
103
2020
64
2021
57
2022
47
2023(2)
43
2025
Target
43
As a responsible energy producer we are committed to pursuing water management strategies that minimize our freshwater use to
help support long-term water security and maintain healthy ecosystems in our operating areas. In 2024, we anticipate investing $3
million in water management to expand our water storage and recycling infrastructure.
Abandonment and Reclamation
Our commitment to responsible resource development also extends to the retirement of our assets at the end of their economic life.
We plan for full lifecycle development of our properties, which includes the abandonment, reclamation, and full restoration at the
end of asset life. At December 31, 2020, we had an end of life well inventory of approximately 4,500 wells. We have committed to
reducing this well inventory to zero by 2040, which represents proactive management of future financial obligations as well as
regulatory compliance.
In 2023, we invested $26 million to complete 291 well abandonments. In 2024, we will continue our abandonment and reclamation
program with approximately $30 million being directed to pipeline, wellbore and facility decommissioning along with well site
reclamations.
Abandonment and Reclamation
Number of wells abandoned (gross)
Spending in abandonment/reclamation ($ million) (3)
2018
110
2019
113
2020
99
2021
237
2022
379
$
14 $
15 $
9 $
10 $
34 $
26 $
2023
2024 Plan
291
260
30
(1) Corporate emissions are reported based on the operating control method of the GHG Protocol. GHG emissions from 2018-2022 are calculated using the Global
Warming Potential ("GWP") values from the IPCC’s Fifth Assessment ("AR5"). We have restated historical emissions with the update to AR5, the operating control
method of the GHG Protocol.
2023 data is not yet third party verified.
Spending includes government grants received for abandonment and reclamations of $2 million in 2020, $3 million in 2021 and $16 million in 2022.
(2)
(3)
6
2023 / Annual Report / Baytex Energy
Year-end 2023 Reserves
Baytex's year-end 2023 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, 2024.
For additional information regarding Baytex's reserves as at December 31, 2023, see Baytex's Annual Information Form for the
year ended December 31, 2023 on Baytex's SEDAR+ profile at www.sedarplus.com, and Baytex's U.S. Form 40-F for the year
ended December 31, 2023 on EDGAR at www.sec.gov/edgar.shtml., each of which are anticipated to be filed on February 28,
2024.
Reserves Summary
On June 20, 2023, Baytex completed the strategic acquisition of Ranger, adding quality scale in the Eagle Ford and reinforcing a
resilient and sustainable business. Our 2023 reserves report reflects this acquisition with a meaningful increase in our reserves
base.
•
•
•
•
•
•
•
•
Proved developed producing ("PDP") reserves increased by 49%, from 124 MMboe to 185 MMboe. Proved reserves
(“1P”) increased by 55%, from 264 MMboe to 410 MMboe. Proved plus probable reserves (“2P”) increased by 51%, from
438 MMboe to 663 MMboe.
Reserves on a 1P basis are comprised of 82% oil and NGLs (46% light oil, 23% NGLs, 12% heavy oil and 1% bitumen)
and 18% natural gas.
In Canada, we invested $463 million on exploration and development expenditures and replaced 131% of production on a
2P basis, net of the divestiture of our Viking assets at Forgan and Plato. The divestiture reduced 1P and 2P reserves by
11 MMboe and 17 MMboe, respectively.
In the Eagle Ford, 1P and 2P reserves increased 117% and 130%, respectively. Reserves associated with the Ranger
assets total 175 MMboe on a 1P basis, and 258 MMboe on a 2P basis, consistent with our assessment of Ranger's
reserves at year-end 2022. The Ranger acquisition enhanced the quality of Baytex’s reserves base, adding high value
light oil and natural gas.
Future development costs (“FDC”) on a 1P basis increased to $6.0 billion ($2.7 billion at year-end 2022) and on a 2P
basis, increased to $9.1 billion ($4.3 billion at year-end 2022). The increase in FDC is largely attributable to the Ranger
acquisition, as well as modest inflationary pressures across our portfolio.
Finding and development ("F&D") costs, including changes in FDC, were $24.23/boe for PDP reserves, $29.82/boe for 1P
reserves and $28.68/boe for 2P reserves.
Generated a PDP recycle ratio of 1.7x and a 1P recycle ratio of 1.4x based on a 2023 operating netback(1) of $41.00/boe.
At year-end 2023, the present value of our 2P reserves, discounted at 10% before tax, is estimated to be $7.8 billion ($5.9
billion at year-end 2022). The increase is largely attributable to the Ranger acquisition and partially offset by the divestiture
of our Viking assets at Forgan and Plato and technical revisions associated with our legacy non-operated Eagle Ford
asset and retained Viking assets.
(1)
Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures
presented by other entities. Refer to the Specified Financial Measures section in this press release for further information.
2023 / Annual Report / Baytex Energy
7
The following table sets forth our gross and net reserves volumes at December 31, 2023 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
Light and
Heavy
Medium Oil Tight Oil
Oil Bitumen Total Oil
(Mbbls)
(Mbbls)
(Mbbls)
(Mbbls)
(Mbbls)
Natural
Gas
Liquids (3)
(Mbbls)
Conventional
Natural Gas (4)
(MMcf)
Shale
Gas
(MMcf)
Total (5)
(Mboe)
9,690
70,573
31,218
1,679
113,159
38,394
52,758
145,556
184,606
Proved developed non-producing
414
3,703
1,416
—
5,533
Proved undeveloped
Total proved
Total probable
Proved plus probable
Net (2)
Proved producing
Proved undeveloped
Total proved
Total probable
Proved plus probable
15,699
88,506
18,445
2,105
124,754
25,803
162,782
51,078
3,783
243,447
14,997
85,238
32,935
45,754
178,923
1,814
54,631
94,840
42,334
1,205
6,761
8,675
23,948
201,607
216,978
77,910
353,924
410,259
38,246
151,764
252,925
40,799
248,020
84,013
49,537
422,370
137,173
116,156
505,688
663,184
9,128
53,944
26,283
1,564
90,918
29,180
47,825
111,300
146,619
14,882
68,154
16,292
1,916
101,243
24,392
124,886
43,834
3,480
196,591
13,910
65,548
27,331
36,517
143,306
1,361
41,630
72,172
32,687
1,076
5,087
6,819
20,760
154,239
172,039
69,661
270,627
325,478
33,578
118,279
201,303
38,302
190,434
71,165
39,997
339,897
104,859
103,238
388,906
526,781
Proved developed non-producing
383
2,789
1,260
—
4,431
“Gross” reserves means the total working interest share of remaining recoverable reserves owned by Baytex before deductions of royalties payable to others.
“Net” reserves means Baytex's gross reserves less all royalties payable to others plus royalty interest reserves.
Notes:
(1)
(2)
(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.
8
2023 / Annual Report / Baytex Energy
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, 2022
Extensions
Technical Revisions (2)
Acquisitions
Dispositions
Economic Factors
Production
December 31, 2023
Light and
Heavy
Medium Oil Tight Oil
Oil Bitumen Total Oil
(Mbbls)
(Mbbls)
(Mbbls)
(Mbbls)
(Mbbls)
Natural
Gas
Liquids (3)
(Mbbls)
Conventional
Natural Gas (4)
(MMcf)
Shale
Gas
(MMcf)
Total (5)
(Mboe)
41,951
48,563
51,058
4,608
146,180
69,765
86,872
202,967
264,251
2,039
21,367
(1,952)
(1,472)
—
108,091
(11,417)
180
—
25
9,402
2,176
7
—
741
—
32,808
8,587
(261)
(1,509)
(3,997)
1,845
4,451
40,849
48,510
(7,782)
(6,062)
—
—
75
108,098
26,379
—
143,499
158,394
(11,417)
1,021
(14)
36
(267)
928
—
86
(11,475)
1,226
(4,999)
(13,793)
(12,305)
(638)
(31,735)
(5,916)
(15,919)
(25,695)
(44,586)
25,803
162,782
51,078
3,783
243,447
94,840
77,910
353,924
410,259
Probable Reserves – Gross Volumes (1) (Forecast Prices)
December 31, 2022
Extensions
Technical Revisions (2)
Acquisitions
Dispositions
Economic Factors
Production
December 31, 2023
Light and
Heavy
Medium Oil Tight Oil
Oil Bitumen Total Oil
(Mbbls)
(Mbbls)
(Mbbls)
(Mbbls)
(Mbbls)
Natural
Gas
Liquids (3)
(Mbbls)
Conventional
Natural Gas (4)
(MMcf)
Shale
Gas
(MMcf)
Total (5)
(Mboe)
21,881
20,719
34,526
45,751
122,877
28,728
45,786
84,633
173,342
289
10,650
3,326
(1,467)
(1,080)
(5,336)
—
54,926
(5,772)
65
—
—
23
—
2
—
416
—
—
25
—
—
(22)
—
14,265
4,510
899
18,478
22,004
(7,857)
(1,730)
(8,835)
(5,274)
(11,939)
54,928
10,794
—
53,785
74,685
(5,772)
482
—
(4)
36
—
(71)
467
—
—
142
—
(5,787)
620
—
14,997
85,238
32,935
45,754
178,923
42,334
38,246
151,764
252,925
Proved Plus Probable Reserves – Gross Volumes (1) (Forecast Prices)
December 31, 2022
Extensions
Technical Revisions (2)
Acquisitions
Dispositions
Economic Factors
Production
December 31, 2023
Light and
Heavy
Medium Oil Tight Oil
Oil Bitumen Total Oil
(Mbbls)
(Mbbls)
(Mbbls)
(Mbbls)
(Mbbls)
63,832
69,283
85,584
50,359
269,058
2,328
32,017
12,728
—
47,073
Natural
Gas
Liquids (3)
(Mbbls)
98,493
13,096
Conventional
Natural Gas (4)
(MMcf)
Shale
Gas
(MMcf)
Total (5)
(Mboe)
132,658
287,600
437,593
2,744
59,327
70,514
(3,419)
(2,552)
(3,160)
(236)
(9,367)
(5,727)
(4,384)
(13,056)
(18,001)
—
163,017
(17,188)
245
—
49
9
—
1,157
—
—
52
163,026
37,172
—
197,284
233,079
(17,188)
1,503
(18)
73
(338)
1,395
—
228
(17,262)
1,846
(4,999) (13,793)
(12,305)
(638)
(31,735)
(5,916)
(15,919)
(25,695)
(44,586)
40,799
248,020
84,013
49,537
422,370
137,173
116,156
505,688
663,184
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) Negative technical revisions in light and medium oil are predominantly associated with higher field operating costs in our Viking asset truncating end of life
forecasts and actual performance not meeting forecast. Negative technical revisions in tight oil, shale gas and natural gas liquids in our legacy non-operated Eagle
Ford assets are predominantly associated with actual performance not meeting forecast and the removal of locations due to inventory consolidation and spacing
changes. Negative probable technical revisions in heavy oil are predominantly associated with performance re-characterization of undeveloped locations in the
Peace River area. Positive proved technical revisions in heavy oil are predominantly associated with improved performance of producing wells in Peace River,
Lloydminster and Peavine areas.
(3) Conventional natural gas includes associated, non-associated and solution gas.
(4) 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.
2023 / Annual Report / Baytex Energy
9
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)
2024
Proved
Reserves
1,038
Proved Plus
Probable Reserves
1,070
2025
2026
2027
2028
Remainder
Total FDC undiscounted
1,256
1,334
1,227
1,060
72
5,986
1,313
1,442
1,580
1,451
2,196
9,051
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)
2023
2022
2021
3 Year
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
1,012.8 $
841.2 $
64.6(1)
28.68 $
3,948.5 $
4,763.6 $
270.2
32.25 $
1,012.8 $
491.7 $
50.5(1)
29.82 $
3,948.5 $
3,290.6 $
190.6
37.98 $
1,012.8 $
41.8(1)
24.23 $
3,948.5 $
104.8
37.69 $
521.5 $
588.6 $
26.2
42.34 $
497.2 $
537.6 $
17.2
60.05 $
521.5 $
320.1 $
21.4
39.40 $
497.2 $
285.0 $
16.6
47.25 $
521.5 $
27.2
19.20 $
497.2 $
26.0
19.13 $
313.3 $
147.4 $
18.8
24.55 $
307.1 $
144.4 $
18.4
24.55 $
313.3 $
308.6 $
35.2
17.67 $
307.1 $
316.8 $
36.1
17.30 $
313.3 $
38.2
8.20 $
307.1 $
38.1
8.06 $
1,847.6
1,577.2
109.6
31.24
4,752.8
5,445.6
305.8
33.35
1,847.6
1,120.4
107.0
27.74
4,752.8
3,892.4
243.2
35.55
1,847.6
107.2
17.24
4,752.8
168.9
28.14
Note:
(1) Gross reserve additions with respect to finding & development costs include 4.7 MMboe of PDP reserve additions, 6.8 MMboe of proved reserves additions and
10.2 MMboe of proved plus probable reserves additions, which in each case, reflect reserves developed on the acquired Ranger assets after closing of the
acquisition. In the reserves reconciliation, these reserve additions are included in the Acquisitions category to align with NI 51-101.
10
2023 / Annual Report / Baytex Energy
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, 2023. 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, 2024.
WTI Crude Oil
US$/bbl
Edmonton Light
Crude Oil
$/bbl
Western
Canadian Select
$/bbl
Henry Hub
US$/MMbtu
AECO Spot
$/MMbtu
Inflation Rate
%/Yr
Exchange Rate
$US/$Cdn
Year
2023 act.
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
77.55
73.67
74.98
76.14
77.66
79.22
80.80
82.42
84.06
85.74
87.46
100.40
92.91
95.04
96.07
97.99
99.95
101.94
103.98
106.06
108.18
110.35
79.60
76.74
79.77
81.12
82.88
85.04
86.74
88.47
90.24
92.04
93.89
2.55
2.75
3.64
4.02
4.10
4.18
4.27
4.35
4.44
4.53
4.62
2.95
2.20
3.37
4.05
4.13
4.21
4.30
4.38
4.47
4.56
4.65
3.9
—
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
0.740
0.752
0.752
0.755
0.755
0.755
0.755
0.755
0.755
0.755
0.755
0.755
Thereafter
Escalation rate of 2.0%
Net Present Value of Reserves (1) (Forecast Prices and Costs)
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, 2023 ($ millions, discounted at)
Proved developed producing
Proved developed non-producing
Proved undeveloped
Total proved
Probable
0%
4,443
291
3,295
8,029
7,773
5%
3,991
223
2,037
6,252
4,445
Total Proved Plus Probable (before tax)
15,802
10,697
Note:
(1)
Includes abandonment, decommissioning and reclamation costs for all producing and non-producing wells and facilities.
10%
3,507
186
1,264
4,957
2,843
7,800
15%
3,133
161
761
4,055
1,971
6,026
Additional Information
Our audited consolidated financial statements for the year ended December 31, 2023 and the related Management's Discussion
and Analysis of the operating and financial results can be accessed on our website at www.baytexenergy.com and will be available
shortly through SEDAR+ at www.sedarplus.com and EDGAR at www.sec.gov/edgar.shtml.
2023 / Annual Report / Baytex Energy
11
Advisory Regarding Forward-Looking Statements
In the interest of providing Baytex's shareholders and potential investors with information regarding Baytex, including management's assessment of
Baytex's future plans and operations, certain statements in this report are "forward-looking statements" within the meaning of the United States
Private Securities Litigation Reform Act of 1995 and "forward-looking information" within the meaning of applicable Canadian securities
legislation (collectively, "forward-looking statements"). In some cases, forward-looking statements can be identified by terminology such as
"believe", "continue", ""estimate", "expect", "forecast", "intend", "may", "objective", "ongoing", "outlook", "potential", "project", "plan",
"should", "target", "would", "will" or similar words suggesting future outcomes, events or performance. The forward-looking statements contained in
this report speak only as of the date thereof and are expressly qualified by this cautionary statement.
Specifically, this report contains forward-looking statements relating to but not limited to: our 2024 strategy including our commitment to a
disciplined, returns-based capital allocation philosophy and the anticipated effect of such philosophy on per-share returns; that we expect to
allocate capital efficiently and respond to changes in regional commodity prices and economic factors; expected annual production growth over the
next five years and our projected 2028 production; our intention to allocate free cash flow to each of debt repayment and shareholder returns
(including share buybacks and quarterly dividends) and the expected amount of such free cash flow to be allocated; our expectation to generate
meaningful free cash flow in 2024, including the anticipated amount and timing thereof; our intention to direct additional free cash flow to
shareholder returns once reaching our total debt target; our total debt target; our intended exploration plans across our heavy oil portfolio, including
our drilling plans; our commodity hedging program, the percentage of our 2024 net crude exposure that is hedged, and the ability of such program
to mitigate volatility in commodity prices; our targeted improvement in operated drilling and completion costs per lateral foot; our guidance
regarding exploration and development expenditures and production in 2024; our drilling plans in the Pembina Duvernay and our intention to
progress the Pembina Duvernay, delineate our Clearwater and Mannville heavy oil positions and deliver strong drilling and completion
performance in the Eagle Ford and Viking regions; our commitment to monitoring GHG emissions, setting targets and pursuing cost-effective
decarbonization strategies; our 2025 GHG emissions intensity reduction target and our strategies to reach the target; our 2024 expected
investment into GHG mitigation, to expand our water storage and recycling infrastructure, and into wellbore and facility decommissioning along
with well site reclamations; our abandonment and reclamation commitments, including the anticipated number of wells; future development
costs, F&D and FD&A; forecast prices for oil and natural gas; forecast inflation and exchange rates; and the net present value before income taxes
of the future net revenue attributable to our reserves. 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: oil and natural gas prices and differentials
between light, medium and heavy crude oil prices; well production rates and reserve volumes; success obtained in drilling new wells; our ability to
add production and reserves through our exploration and development activities; capital expenditure levels; operating costs; 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; our ability to
market oil and natural gas successfully; that we will have sufficient financial resources in the future to provide shareholder returns; 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 risk of an extended period of low oil and natural gas prices; risks associated with our ability
to develop our properties and add reserves; that we may not achieve the expected benefits of acquisitions and we may sell assets below their
carrying value; the availability and cost of capital or borrowing; restrictions or costs imposed by climate change initiatives and the physical risks of
climate change; the impact of an energy transition on demand for petroleum productions; availability and cost of gathering, processing and pipeline
systems; retaining or replacing our leadership and key personnel; changes in income tax or other laws or government incentive programs; risks
associated with large projects; risks associated with higher a higher concentration of activity and tighter drilling spacing; costs to develop and
operate our properties; risks associated with achieving our total debt target, production guidance, exploration and development expenditures
guidance; the amount of free cash flow we expect to generate; risk that the board of directors determines to allocate capital other than as set forth
herein; current or future controls, legislation or regulations; restrictions on or access to water or other fluids; public perception and its influence on
the regulatory regime; new regulations on hydraulic fracturing; regulations regarding the disposal of fluids; risks associated with our hedging
activities; variations in interest rates and foreign exchange rates; uncertainties associated with estimating oil and natural gas reserves; our inability
to fully insure against all risks; risks associated with a third-party operating our Eagle Ford properties; additional risks associated with our thermal
heavy crude oil projects; our ability to compete with other organizations in the oil and gas industry; risk that we do not achieve our GHG emissions
intensity reduction target; risks associated with our use of information technology systems; adverse results of litigation; that our Credit Facilities may
not provide sufficient liquidity or may not be renewed; failure to comply with the covenants in our debt agreements; risks associated with expansion
into new activities; the impact of Indigenous claims; risks of counterparty default; impact of geopolitical risk and conflicts; loss of foreign private
issuer status; conflicts of interest between the Corporation and its directors and officers; variability of share buybacks and dividends; 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. Readers are cautioned that the foregoing list
of risk factors is not exhaustive.New risk factors emerge from time to time, and it is not possible for management to predict all of such factors and to
assess in advance the impact of each such factor on our business or the extent to which any factor, or combination of factors, may cause actual
results to differ materially from those contained in any forward-looking statements.
The future acquisition of our common shares pursuant to a share buyback (including through its NCIB), if any, and the level thereof is uncertain.
Any decision to pay dividends on the Common Shares (including the actual amount, the declaration date, the record date and the payment date in
connection therewith) or acquire Common Shares pursuant to a share buyback will be subject to the discretion of the Board and may depend on a
variety of factors, including, without limitation, the Corporation's business performance, financial condition, financial requirements, growth plans,
expected capital requirements and other conditions existing at such future time including, without limitation, contractual restrictions (including
covenants contained in the agreements governing any indebtedness that the Corporation has incurred or may incur in the future, including the
terms of the Credit Facilities) and satisfaction of the solvency tests imposed on the Corporation under applicable corporate law. There can be no
12
2023 / Annual Report / Baytex Energy
assurance of the number of Common Shares that the Corporation will acquire pursuant to a share buyback, if any, in the future. Further, the
payment of dividends to shareholders is not assured or guaranteed and dividends may be reduced or suspended entirely.
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, 2023, to be filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange
Commission on February 28, 2024 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.
This report contains information that may be considered a financial outlook under applicable securities laws about the Corporation's
potential financial position, including, but not limited to, our 2024 guidance for development expenditures; our expected 2024 free cash flow; and
our intentions of allocating our annual free cash flow to shareholder returns through a share buyback and debt reduction; all of which are subject to
numerous assumptions, risk factors, limitations and qualifications, including those set forth in the above paragraphs. The actual results
of operations of the Corporation and the resulting financial results will vary from the amounts set forth in this report and such variations may be
material. This information has been provided for illustration only and with respect to future periods are based on budgets and forecasts that
are speculative and are subject to a variety of contingencies and may not be appropriate for other purposes. Accordingly, these estimates are not to
be relied upon as indicative of future results. Except as required by applicable securities laws, the Corporation undertakes no obligation to update
such financial outlook, whether as a result of new information, future events or otherwise. The financial outlook contained in this report was made
as of the date of this report and was provided for the purpose of providing further information about the Corporation's potential future
business operations. Readers are cautioned that the financial outlook contained in this report is not conclusive and is subject to change.
All amounts in this report are stated in Canadian dollars unless otherwise specified.
Specified Financial Measures
In this report, we refer to certain financial measures (such as free cash flow, operating netback, working capital deficiency, average royalty rate and
total sales, net of blending and other expense) which do not have any standardized meaning prescribed by IFRS. While these measures are
commonly used in the oil and gas industry, our determination of these measures may not be comparable with calculations of similar measures
presented by other reporting issuers. This report also contains the terms "adjusted funds flow" and "net debt" which are considered capital
management measures. We believe that inclusion of these specified financial measures provides useful information to financial statement
users when evaluating the financial results of Baytex.
Non-GAAP Financial Measures
Total sales, net of blending and other expense
Total sales, net of blending and other expense represents the revenues realized from produced volumes during a period. Total sales, net
of blending and other expense is comprised of total petroleum and natural gas sales adjusted for blending and other expense. We believe including
the blending and other expense associated with purchased volumes is useful when analyzing our realized pricing for produced volumes
against benchmark commodity prices.
Operating netback
Operating netback is used to assess our operating performance and our ability to generate cash margin on a unit of production basis.
Operating netback is comprised of petroleum and natural gas sales, less blending expense, royalties, operating expense and transportation
expense.
The following table reconciles operating netback to petroleum and natural gas sales.
($ thousands)
Three Months Ended
Years Ended December 31
December 31,
2023
September 30,
2023
December 31,
2022
2023
2022
Petroleum and natural gas sales
$
1,065,515 $
1,163,010 $
648,986 $
3,382,621 $
2,889,045
Blending and other expense
Total sales, net of blending and other expense
Royalties
Operating expense
Transportation expense
Operating netback
Free cash flow
(62,296)
1,003,219
(228,570)
(164,873)
(29,744)
(49,830)
1,113,180
(240,049)
(174,119)
(27,983)
(50,174)
(224,802)
(189,454)
598,812
3,157,819
2,699,591
(121,691)
(669,792)
(562,964)
(104,335)
(570,839)
(422,666)
(14,817)
(89,306)
(48,561)
$
580,032 $
671,029 $
357,969 $
1,827,882 $
1,665,400
We use free cash flow to evaluate our financial performance and to assess the cash available for debt repayment, common share repurchases,
dividends and acquisition opportunities. Free cash flow is comprised of cash flows from operating activities adjusted for changes in non-cash
working capital, transaction costs, additions to exploration and evaluation assets, additions to oil and gas properties, payments on lease obligations,
and cash premiums on derivatives.
2023 / Annual Report / Baytex Energy
13
Free cash flow is reconciled to cash flows from operating activities in the following table.
($ thousands)
Three Months Ended
Years Ended December 31
December 31,
2023
September 30,
2023
December 31,
2022
2023
2022
Cash flows from operating activities
$
474,452 $
444,033 $
303,441 $
1,295,731 $
1,172,872
Change in non-cash working capital
Transaction costs
Additions to exploration and evaluation assets
14,971
5,079
1,271
126,075
(55,632)
2,263
(40)
—
(462)
220,895
49,045
—
(26,072)
—
(6,359)
Additions to oil and gas properties
(200,537)
(409,151)
(103,172)
(1,012,787)
(515,183)
Payments on lease obligations
Cash premiums on derivatives
(4,451)
—
(4,740)
—
(851)
—
(11,527)
2,263
(3,732)
—
Free cash flow
$
290,785 $
158,440 $
143,324 $
543,620 $
621,526
Working capital deficiency
Working capital deficiency is calculated as cash, trade receivables, and prepaids and other assets net of trade payables, dividends payable, other
long-term liabilities and share-based compensation liability. Working capital deficiency is used by management to measure the Company's liquidity.
At December 31, 2023, the Company had $587.8 million of available credit facility capacity to cover any working capital deficiencies.
The following table summarizes the calculation of working capital deficiency.
($ thousands)
Cash
Trade receivables
Prepaids and other assets
Trade payables
Share-based compensation liability
Other long-term liabilities
Dividends payable
Working capital deficiency
Non-GAAP Financial Ratios
December 31, 2023
September 30, 2023
December 31, 2022
As at
$
(55,815) $
(23,899) $
(339,405)
(83,259)
477,295
35,732
19,147
18,381
$
72,076 $
(540,679)
—
685,392
—
—
19,138
139,952 $
(5,464)
(222,108)
(6,377)
227,332
54,072
—
—
47,455
Total sales, net of blending and other expense per boe
Total sales, net of blending and other per boe is used to compare our realized pricing to applicable benchmark prices and is calculated as total
sales, net of blending and other expense (a non-GAAP financial measure) divided by barrels of oil equivalent production volume for the applicable
period.
Average royalty rate
Average royalty rate is used to evaluate the performance of our operations from period to period and is comprised of royalties divided by total sales,
net of blending and other expense (a non-GAAP financial measure). 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.
Operating netback per boe
Operating netback per boe is equal to operating netback (a non-GAAP financial measure) divided by barrels of oil equivalent sales volume for the
applicable period and is used to assess our operating performance on a unit of production basis.
Capital Management Measures
Net debt
We use net debt to monitor our current financial position and to evaluate existing sources of liquidity. We also use net debt projections to estimate
future liquidity and whether additional sources of capital are required to fund ongoing operations. Net debt is comprised of our credit facilities and
long-term notes outstanding adjusted for unamortized debt issuance costs, trade payables, share-based compensation liability, dividends payable,
other long-term liabilities, cash, trade receivables, and prepaids and other assets.
14
2023 / Annual Report / Baytex Energy
The following table summarizes our calculation of net debt.
As at
($ thousands)
December 31, 2023
September 30, 2023
December 31, 2022
Credit facilities
Unamortized debt issuance costs - Credit facilities (1)
Long-term notes
Unamortized debt issuance costs - Long-term notes (1)
Trade payables
Share-based compensation liability
Dividends payable
Other long-term liabilities
Cash
Trade receivables
Prepaids and other assets
Net debt
$
848,749 $
1,028,867 $
15,987
1,562,361
35,114
477,295
35,732
18,381
19,147
(55,815)
(339,405)
(83,259)
17,889
1,600,397
37,243
685,392
—
19,138
—
(23,899)
(540,679)
—
$
2,534,287 $
2,824,348 $
383,031
2,363
547,598
6,999
227,332
54,072
—
—
(5,464)
(222,108)
(6,377)
987,446
(1) Unamortized debt issuance costs were obtained from Note 8 Credit Facilities and Note 9 Long-term Notes from the Consolidated Financial Statements for the year
ended December 31, 2023.
Adjusted funds flow
Adjusted funds flow is used to monitor operating performance and our ability to generate funds for exploration and development expenditures and
settlement of abandonment obligations. Adjusted funds flow is comprised of cash flows from operating activities adjusted for changes in non-cash
working capital, asset retirement obligations settled, transaction costs, and cash premiums on derivatives during the applicable period.
Adjusted funds flow is reconciled to amounts disclosed in the primary financial statements in the following table.
($ thousands)
Three Months Ended
Years Ended December 31
December 31,
2023
September 30,
2023
December 31,
2022
2023
2022
Cash flows from operating activities
$
474,452 $
444,033 $
303,441 $
1,295,731 $
1,172,872
Change in non-cash working capital
Asset retirement obligations settled
Transaction costs
Cash premiums on derivatives
14,971
7,646
5,079
—
126,075
9,252
2,263
—
(55,632)
7,743
—
—
220,895
26,416
49,045
2,263
(26,072)
18,351
—
—
Adjusted funds flow
$
502,148 $
581,623 $
255,552 $
1,594,350 $
1,165,151
Advisory Regarding Oil and Gas Information
The reserves information contained in this report has been prepared in accordance with NI 51-101. Complete NI 51-101 reserves disclosure will be
included in our Annual Information Form for the year ended December 31, 2023, which will be filed on February 28, 2024. Listed below are
cautionary statements that are specifically required by NI 51-101:
•
•
•
The term barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic
feet of natural gas to one boe (6 mcf/bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and
does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to
natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an
indication of value.
With respect to finding and development costs, the aggregate of the exploration and development costs incurred in the most recent
financial year and the change during that year in estimated future development costs generally will not reflect total finding and
development costs related to reserves additions for that year.
This report contains estimates of the net present value of our future net revenue from our reserves. Such amounts do not
represent the fair market value of our reserves.
This report discloses drilling inventory and potential drilling locations. Drilling inventory and drilling locations refers to Baytex's 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.
2023 / Annual Report / Baytex Energy
15
In the Eagle Ford, Baytex’s net drilling locations include 358 proved and 148 probable locations as at December 31, 2023 and 318 unbooked
locations. In the Viking, Baytex’s net drilling locations include 586 proved and 173 probable locations as at December 31, 2023 and 238 unbooked
locations. In Peace River (including Clearwater), Baytex’s net drilling locations include 64 proved and 52 probable locations as at December 31,
2023 and 331 unbooked locations. In Lloydminster, Baytex’s net drilling locations include 73 proved and 69 probable locations as at December 31,
2023 and 263 unbooked locations. In the Duvernay, Baytex’s net drilling locations include 23 proved and 24 probable locations as at December 31,
2023 and 174 unbooked locations.
Throughout this report, “oil and NGL” refers to heavy oil, bitumen, light and medium oil, tight oil, condensate and natural gas liquids (“NGL”) product
types as defined by NI 51-101. The following table shows Baytex’s disaggregated production volumes for the three and twelve months ended
December 31, 2023. The NI 51-101 product types are included as follows: “Heavy Oil” - heavy oil and bitumen, “Light and Medium Oil” - light and
medium oil, tight oil and condensate, “NGL” - natural gas liquids and “Natural Gas” - shale gas and conventional natural gas.
Three Months Ended December 31, 2023
Twelve Months Ended December 31, 2023
Heavy Oil
(bbl/d)
Light and
Medium
Oil (bbl/d)
NGL
(bbl/d)
Natural
Gas
(Mcf/d)
Oil
Equivalent
(boe/d)
Heavy Oil
(bbl/d)
Light and
Medium
Oil (bbl/d)
NGL
(bbl/d)
Natural
Gas
(Mcf/d)
Oil
Equivalent
(boe/d)
10,494
12,736
16,338
8
40
—
29
—
—
10,576
1,445
—
12,294
13,017
16,338
10,209
11,852
13,399
9
23
—
44
—
—
11,258
1,298
—
12,138
12,092
13,399
—
—
—
10,560
2,805
730
158
2,129
622
11,592
12,650
6,748
18,211
6,058
4,386
—
—
—
13,126
1,884
656
196
1,195
654
11,834
15,295
3,840
19,224
3,719
4,514
—
55,981
20,223
116,548
95,629
—
37,691
12,214
66,556
60,997
Canada – Heavy
Peace River
Lloydminster
Peavine
Canada - Light
Viking
Duvernay
Remaining Properties
United States
Eagle Ford
Total
39,569
70,123
23,160
165,121
160,373
35,460
53,389
14,303
114,011
122,154
This report contains metrics commonly used in the oil and natural gas industry, such as “finding and development costs”, “finding,
development and acquisition costs”, “PDP recycle ratio" and "1P recycle ratio." These terms do not have a standardized meaning and may not be
comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons. Such metrics have
been included in this report to provide readers with additional measures to evaluate Baytex’s performance, however, such measures are not reliable
indicators of Baytex’s future performance and future performance may not compare to Baytex’s performance in previous periods and
therefore such metrics should not be unduly relied upon.
Finding and development costs are calculated on a per boe basis by dividing the aggregate of the change in future development costs from the
prior year for the particular reserves 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 reserves 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.
Recycle ratio is calculated by dividing operating netback on a per boe basis by finding and development costs for the particular reserves category.
References herein to average 30-day initial production rates and other short-term production rates are useful
in confirming the presence of
hydrocarbons, however, such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are
not indicative of long term performance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in
calculating aggregate production for us or the assets for which such rates are provided. A pressure transient analysis or well-test interpretation has
not been carried out in respect of all wells. Accordingly, we caution that the test results should be considered to be preliminary.
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.
16
2023 / Annual Report / Baytex Energy
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.
2023 / Annual Report / Baytex Energy
17
BAYTEX ENERGY CORP.
Management’s Discussion and Analysis
For the years ended December 31, 2023 and 2022
Dated February 28, 2024
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, 2023 and 2022. This information is provided as of February 28, 2024. 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, 2023
("Q4/2023" and "2023") have been compared with the results for the three months and year ended December 31, 2022 ("Q4/2022"
and "2022"). 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, 2023 and 2022, together with the accompanying notes and
the Annual Information Form ("AIF") for the year ended December 31, 2023. These documents and additional information about
Baytex are accessible on the SEDAR+ website at www.sedarplus.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 in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting
Standards Board. The terms "operating netback", "free cash flow", "average royalty rate", "heavy oil, net of blending and other
expense" and "total sales, net of blending and other expense" are specified financial measures that do not have any standardized
meaning as prescribed by IFRS and therefore may not be comparable to similar measures presented by other companies where
similar terminology is used. This MD&A also contains the terms "adjusted funds flow" and "net debt" which are capital management
measures. Refer to our advisory on forward-looking information and statements and a summary of our specified financial measures
at the end of the MD&A.
BAYTEX ENERGY CORP.
Baytex Energy Corp. is a North American focused energy company based in Calgary, Alberta. The Company operates in Canada
and the United States ("U.S."). The Canadian operating segment includes our light oil assets in the Viking and Duvernay, our heavy
oil assets in Peace River and Lloydminster and our conventional oil and natural gas assets in Western Canada. The U.S. operating
segment includes our Eagle Ford operated and non-operated assets in Texas.
On June 20, 2023, Baytex and Ranger Oil Corporation ("Ranger") completed the merger of the two companies (the "Merger")
whereby Baytex acquired all of the issued and outstanding common shares of Ranger. The Merger increased our Eagle Ford scale
and provides an operating platform to effectively allocate capital across the Western Canadian Sedimentary Basin and the Eagle
Ford. Production from the Ranger assets is approximately 80% weighted towards high netback light oil and liquids and is primarily
operated which increases our ability to effectively allocate capital.
We issued 311.4 million common shares, paid $732.8 million in cash and assumed $1.1 billion of Ranger's net debt(1). The cash
portion of the transaction was funded with an expanded US$1.1 billion credit facility, a US$150 million two-year term loan facility
and the net proceeds from the issuance of US$800 million senior unsecured notes due 2030.
(1) Capital management measure. Refer to the Specified Financial Measures section in this MD&A for further information
18
2023 / Annual Report / Baytex Energy
2023 ANNUAL HIGHLIGHTS
Baytex delivered strong operating and financial results in 2023. Our annual results include six months of operations following the
Merger with Ranger and demonstrate the strength of our increased scale and diversified North American oil-weighted portfolio.
Annual production of 122,154 boe/d was consistent with our revised annual guidance of 121,500 to 122,000 boe/d and reflects
strong results from our drilling programs in Western Canada and the Eagle Ford in Texas. We invested $1.0 billion in exploration
and development expenditures and generated free cash flow(1) of $543.6 million in 2023.
Exploration and development expenditures totaled $1.0 billion for 2023. In the U.S. we invested $549.6 million during 2023 and
production averaged 60,997 boe/d which is higher than 28,245 boe/d in 2022 due to the Merger. We invested $463.2 million in
Canada in 2023 and generated production of 61,157 boe/d during 2023 compared to 55,275 boe/d in 2022 which reflects growth
driven by strong well performance from our heavy oil operations at Peavine.
Oil prices were lower in 2023 as a result of global supply growth which has resulted in a more balanced crude market relative to
2022 when prices were elevated as the global supply shortfall was exacerbated by uncertainty related to Russian supply. The
average WTI benchmark price for 2023 was US$77.62/bbl which was US$16.61/bbl lower than 2022 when WTI averaged
US$94.23/bbl.
Adjusted funds flow(2) of $1.6 billion in 2023 was higher than $1.2 billion for 2022 which reflects higher production following the
Merger partially offset by lower realized pricing due to the decline in benchmark prices. Free cash flow of $543.6 million in 2023
was lower than $621.5 million for 2022 due to lower benchmark prices, inflationary pressures in Canada and the U.S. along with
increased development activity following the Merger. Cash flows from operating activities increased to $1.3 billion in 2023
compared to $1.2 billion in 2022. The net loss of $233.4 million for 2023 includes an impairment loss of $833.7 million compared to
net income of $855.6 million in 2022 which included impairment reversals of $267.7 million.
Net debt(2) of $2.5 billion at December 31, 2023 was $1.5 billion higher than $1.0 billion at December 31, 2022 due to the cash
consideration paid and net debt assumed in conjunction with the Merger. Since the Merger on June 20, 2023, we have paid down
$280.6 million of net debt and increased our shareholder returns to 50% of free cash flow which allowed us to increase our share
buyback program and introduce a dividend. The remainder of our free cash flow will be allocated to the balance sheet.
On June 23, 2023, we renewed our Normal Course Issuer Bid ("NCIB") with the Toronto Stock Exchange for a share buyback
program for up to 68.4 million shares (10% of our public float at the time). During 2023 we repurchased 40.5 million shares for
$221.9 million representing 5% of the outstanding shares at the inception of the NCIB renewal. On October 2, 2023 and January 2,
2024, we paid a quarterly cash dividend of CDN$0.0225 per share as part of our shareholder returns commitment. On February 28,
2024, the Company's Board of Directors declared a quarterly cash dividend of $0.0225 per share to be paid on April 1, 2024 for
shareholders of record on March 15, 2024. These dividends are designated as “eligible dividends” for Canadian income tax
purposes. For U.S. income tax purposes, Baytex’s dividends are considered “qualified dividends.”
(1) Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation
of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.
(2) Capital management measure. Refer to the Specified Financial Measures section in this MD&A for further information
2023 / Annual Report / Baytex Energy
19
GUIDANCE
Our 2024 annual guidance includes exploration and development expenditures of $1.2 - $1.3 billion and is designed to generate
annual production of 150,000 - 156,000 boe/d. Our annual production guidance remains unchanged despite weather-related
disruptions in Texas that we estimate will result in Q1/2024 production that is approximately 2,000 boe/d lower than our budget
expectation.
The following table compares our 2023 revised annual guidance and 2024 annual guidance to our 2023 results. Production,
exploration and development expenditures, and expenses were relatively consistent with our revised annual guidance for 2023
which reflects our ongoing efforts to deliver strong operating results while we maintain a competitive cost structure. A higher
proportion of our 2024 production will be from the Eagle Ford which will result in a modest increase in our per unit expected
transportation costs for 2024 relative to our 2023 results along with a decrease in our operating costs. We continue to use free
cash flow for debt repayment and expect cash interest of $3.40/boe in 2024 compared to $3.58/boe in 2023.
Exploration and development expenditures
2023 Revised
Annual Guidance (1)
~ $1,035 million
2023 Results 2024 Annual Guidance (2)
$1.2 - $1.3 billion
$1,012.8 million
Production (boe/d)
121,500 - 122,000 boe/d
122,154 boe/d
150,000 - 156,000
Expenses:
Average royalty rate (3)
Operating (4)
Transportation (4)
General and administrative (4)
Cash Interest (4)
Current Income Taxes (5)
21.0% - 22.0%
~ $12.75/boe
~ $2.10/boe
21.2%
23%
$12.80/boe
$11.25 - $12.00/boe
$2.00/boe
$2.35 - $2.55/boe
$80 million ($1.80/boe)
$70 million ($1.57/boe)
$92 million ($1.65/boe)
$156 million ($3.50/boe)
$160 million ($3.58/boe)
$190 million ($3.40/boe)
$14 million ($0.31/boe)
$11 million ($0.24/boe)
$40 million ($0.72/boe)
Leasing expenditures
Asset retirement obligations settled
$13 million
$25 million
$12 million
$26 million
$12 million
$30 million
(1) As announced on November 2, 2023.
(2) As announced on December 6, 2023.
(3) Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation
of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.
(4) Refer to Operating Expense, Transportation Expense, General and Administrative Expense and Financing and Interest Expense sections of
this MD&A for description of the composition of these measures.
(5) Current income tax expense per boe is calculated as current income tax expense divided by barrels of oil equivalent production volume for the
applicable period.
20
2023 / Annual Report / Baytex Energy
RESULTS OF OPERATIONS
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 operated and non-operated assets in Texas.
Production
Daily Production
Liquids (bbl/d)
Light oil and condensate
Heavy oil
Natural Gas Liquids ("NGL")
Total liquids (bbl/d)
Natural gas (mcf/d)
Total production (boe/d)
Production Mix
Segment as a percent of total
Light oil and condensate
Heavy oil
NGL
Natural gas
Years Ended December 31
2023
2022
Canada
U.S.
Total
Canada
U.S.
Total
15,698
35,460
2,090
53,248
47,454
61,157
37,691
—
12,214
49,905
66,556
60,997
53,389
35,460
14,304
103,153
114,010
122,154
16,060
28,993
1,896
46,949
49,954
55,275
17,041
—
5,679
22,720
33,146
28,245
33,101
28,993
7,575
69,669
83,101
83,519
50%
50%
100%
66%
34%
100%
26%
58%
3%
13%
62%
—%
20%
18%
44%
29%
12%
15%
29%
52%
3%
16%
60%
—%
20%
20%
40%
35%
9%
16%
Production averaged 122,154 boe/d in 2023 compared to 83,519 boe/d in 2022. Production was higher in 2023 primarily due to the
production contribution from the properties acquired from Ranger along with our successful development program in Canada.
In Canada, production increased to 61,157 boe/d in 2023 compared to 55,275 boe/d in 2022. The 5,882 boe/d increase in
production is primarily due to strong well performance from our Clearwater heavy oil development program at Peavine.
In the U.S., production was 60,997 boe/d in 2023 compared to 28,245 boe/d for 2022. The production from the Merger contributed
to the 32,752 boe/d increase in production for 2023 relative to 2022. Production from the acquired Eagle Ford assets is primarily
operated and is weighted towards light oil which resulted in a higher proportion of our total production being light oil in 2023.
Total production of 122,154 boe/d for 2023 was consistent with our revised annual guidance of approximately 121,500 - 122,000
boe/d. We expect production in 2024 to average 150,000 - 156,000 boe/d which is consistent with the production for the second
half of 2023 and includes the impact of the non-core Viking disposition which was producing approximately 4,000 boe/d when the
sale was completed in December 2023.
COMMODITY PRICES
The prices received for our crude oil and natural gas production directly impact our earnings, free cash flow and our financial
position.
Crude Oil
Global benchmark prices for crude oil were lower throughout 2023 relative to 2022 as a result of global supply growth which has
resulted in a more balanced crude oil market relative to 2022 when prices were elevated as the global supply shortfall was
exacerbated by uncertainty related to Russian supply. OPEC curtailed production during the second half of 2023 to stabilize the
market after a period of weaker prices in the first half of 2023. As a result of these factors, the WTI benchmark price averaged
US$77.62/bbl for 2023 which was US$16.61/bbl lower than US$94.23/bbl for 2022 when WTI was higher due to uncertainty around
global supply caused by Russia's invasion of Ukraine.
2023 / Annual Report / Baytex Energy
21
We compare the price received for our U.S. crude oil production to the Magellan East Houston ("MEH") stream at Houston, Texas
which is a representative benchmark for light oil pricing at the U.S. Gulf coast. The MEH benchmark typically trades at a premium
to WTI as a result of access to global markets. The MEH benchmark averaged US$79.29/bbl during 2023, representing a premium
of US$1.67/bbl relative to WTI, compared to US$97.79/bbl or a premium of US$3.57/bbl for 2022. Reduced demand on the Gulf
Coast during 2023 resulted in a slightly lower premium compared to 2022 when there was heightened uncertainty over global
supply.
Prices for Canadian oil trade at a discount to WTI due to a lack of egress to diversified markets from Western Canada. Differentials
for Canadian oil prices relative to WTI fluctuate based on production and inventory levels in Western Canada.
We compare the price received for our light oil production in Canada to the Edmonton par benchmark oil price. The Edmonton par
price averaged $100.46/bbl for 2023 compared to $119.95/bbl for 2022. Edmonton par traded at a US$3.18/bbl discount to WTI in
2023 compared to a discount of US$2.07/bbl for 2022.
We compare the price received for our heavy oil production in Canada to the WCS heavy oil benchmark. The WCS benchmark
price for 2023 averaged $79.58/bbl compared to $98.94/bbl for 2022. The WCS differential to WTI was US$18.65/bbl in 2023 which
is consistent with US$18.21/bbl in 2022.
Natural Gas
Reduced demand for North American gas resulted in lower prices in 2023 relative to 2022 which was impacted by geopolitical
factors that caused higher global natural gas prices due to uncertainty of supply to Europe.
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$2.74/mmbtu for 2023 compared to US$6.64/mmbtu for 2022.
In Canada, we receive natural gas pricing based on the AECO benchmark which continues to trade at a discount to NYMEX as a
result of limited market access for Canadian natural gas production. The AECO benchmark averaged $2.93/mcf during 2023 which
is lower than $5.56/mcf during 2022.
The following tables compare select benchmark prices and our average realized selling prices for the years ended December 31,
2023 and 2022.
Benchmark Averages
WTI oil (US$/bbl) (1)
MEH oil (US$/bbl) (2)
MEH oil differential to WTI (US$/bbl)
Edmonton par oil ($/bbl) (3)
Edmonton par oil differential to WTI (US$/bbl)
WCS heavy oil ($/bbl) (4)
WCS heavy oil differential to WTI (US$/bbl)
AECO natural gas price ($/mcf) (5)
NYMEX natural gas price (US$/mmbtu) (6)
CAD/USD average exchange rate
Years Ended December 31
2023
2022
Change
77.62
79.29
1.67
100.46
(3.18)
79.58
(18.65)
2.93
2.74
1.3495
94.23
97.79
3.57
119.95
(2.07)
98.94
(18.21)
5.56
6.64
1.3016
(16.61)
(18.50)
(1.90)
(19.49)
(1.11)
(19.36)
(0.44)
(2.63)
(3.90)
0.0479
(1) WTI refers to the arithmetic average of NYMEX prompt month WTI for the applicable period.
(2) MEH refers to arithmetic average of the Argus WTI Houston differential weighted index price for the applicable period.
(3) Edmonton par refers to the average posting price for the benchmark MSW crude oil.
(4) WCS refers to the average posting price for the benchmark WCS heavy oil.
(5) AECO refers to the AECO arithmetic average month-ahead index price published by the Canadian Gas Price Reporter ("CGPR").
(6) NYMEX refers to the NYMEX last day average index price as published by the CGPR.
22
2023 / Annual Report / Baytex Energy
Years Ended December 31
2023
2022
Canada
U.S.
Total
Canada
U.S.
Total
Average Realized Sales Prices
Light oil and condensate ($/bbl) (1)
Heavy oil, net of blending and other expense
($/bbl) (2)
NGL ($/bbl) (1)
Natural gas ($/mcf) (1)
Total sales, net of blending and other expense
($/boe) (2)
$
100.34 $
105.71 $
104.13 $
118.23 $
125.00 $
121.72
66.19
30.38
2.83
—
27.55
3.15
66.19
27.96
3.02
86.24
44.57
5.52
—
43.25
7.88
86.24
43.58
6.46
$
67.39 $
74.27 $
70.82 $
86.10 $
93.36 $
88.56
(1) Calculated as light oil and condensate, NGL or natural gas sales divided by barrels of oil equivalent production volume for the applicable
period.
(2) Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation
of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.
Average Realized Sales Prices
Our total sales, net of blending and other expense per boe(1) was $70.82/boe for 2023 compared to $88.56/boe for 2022. In
Canada, our realized sales price of $67.39/boe for 2023 was lower than $86.10/boe for 2022 and our realized sales price in the
U.S. of $74.27/boe in 2023 decreased from $93.36/boe in 2022. The decrease in our realized price in Canada and the U.S. for
2023 was a result of lower North American benchmark prices relative to 2022.
We compare our light oil realized price in Canada to the Edmonton par benchmark price. Our realized light oil and condensate
price(2) in 2023 was $100.34/bbl compared to $118.23/bbl in 2022. The decrease in our realized light oil and condensate price for
2023 was primarily a result of lower benchmark prices. Our realized price represents a discount of $0.12/bbl to the Edmonton par
benchmark which reflects higher Duvernay production in the second half of 2023 which resulted in a narrower discount relative to
$1.72/bbl in 2022.
We compare the price received for our U.S. light oil and condensate production to the MEH benchmark. Our realized light oil and
condensate price averaged $105.71/bbl for 2023 compared to $125.00/bbl for 2022. Expressed in U.S. dollars, our realized light oil
and condensate price of US$78.33/bbl for 2023 was lower than US$96.04/bbl in 2022 and represents discounts to MEH of
US$0.96/bbl for 2023 which is narrower than a discount of US$1.75/bbl in 2022. The narrower discount in 2023 reflects the
additional production from the Merger in the second half of the year when the MEH benchmark was higher relative to the annual
average benchmark price.
Our realized heavy oil price, net of blending and other expense(1) averaged $66.19/bbl in 2023 compared to $86.24/bbl in 2022. The
$20.05/bbl decrease in our realized heavy oil price, net of blending and other expense is consistent with a $19.36/bbl decrease in
WCS benchmark in 2023 compared to 2022.
Our realized NGL price(2) as a percentage of WTI will vary based on the product mix of our NGL volumes and changes in the
market prices of the underlying products. Our realized NGL price was $27.96/bbl in 2023 or 27% of WTI (expressed in Canadian
dollars) compared to $43.58/bbl or 36% of WTI (expressed in Canadian dollars) in 2022. Our realized NGL price in Canada and the
U.S. was lower as a percentage of WTI in 2023 relative to 2022 which reflects lower demand as a result of increased production in
North America.
We compare our realized natural gas price in the U.S. to the NYMEX benchmark and to the AECO benchmark price in Canada. A
portion of our natural gas sales in Canada and the U.S. are based on the respective daily index prices which fluctuate
independently from the associated monthly index prices. Our realized natural gas price(2) in Canada was $2.83/mcf for 2023
compared to $5.52/mcf for 2022. In the U.S., our realized natural gas price was US$2.33/mcf for 2023 compared to US$6.05/mcf
for 2022. The decrease in our realized gas price in Canada and the U.S. is consistent with the decreases in the AECO monthly and
NYMEX monthly benchmark prices in 2023 compared to 2022.
(1) Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation
of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.
(2) Calculated as light oil and condensate, NGL or natural gas sales divided by barrels of oil equivalent production volume for the applicable
period.
2023 / Annual Report / Baytex Energy 23
PETROLEUM AND NATURAL GAS SALES
($ thousands)
Oil sales
Years Ended December 31
2023
2022
Canada
U.S.
Total
Canada
U.S.
Total
Light oil and condensate
$ 574,910 $ 1,454,213 $ 2,029,123 $ 693,043 $ 777,506 $ 1,470,549
Heavy oil
NGL
Total liquids sales
Natural gas sales
1,081,549
—
1,081,549
1,102,076
—
1,102,076
23,174
122,823
145,997
30,847
89,658
120,505
1,679,633
1,577,036
3,256,669
1,825,966
867,164
2,693,130
49,388
76,564
125,952
100,595
95,320
195,915
Total petroleum and natural gas sales
1,729,021
1,653,600
3,382,621
1,926,561
962,484
2,889,045
Blending and other expense
(189,454)
Total sales, net of blending and other expense (1) $ 1,504,219 $ 1,653,600 $ 3,157,819 $ 1,737,107 $ 962,484 $ 2,699,591
(1) Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation
(189,454)
(224,802)
(224,802)
—
—
of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.
Total sales, net of blending and other expense, of $3.2 billion for 2023 increased $458.2 million from $2.7 billion for 2022. The
Merger with Ranger along with higher production from our successful development programs resulted in an increase in total sales
in 2023 relative to 2022 partially offset by the effect of lower benchmark prices.
In Canada, total sales, net of blending and other expense, was $1.5 billion for 2023 which is a decrease of $232.9 million from $1.7
billion reported for 2022. The decrease in total petroleum and natural gas sales was the result of lower realized pricing for 2023
relative to 2022 which resulted in a $417.7 million decrease in total sales, net of blending and other expense. The effect of lower
realized pricing was partially offset by higher production which resulted in a $184.8 million increase in total sales, net of blending
and other expense, relative to 2022.
In the U.S., petroleum and natural gas sales of $1.7 billion in 2023 was $691.1 million higher than $962.5 million reported for 2022.
Higher production in 2023 relative to 2022 was primarily due to the Merger with Ranger and contributed to a $1.1 billion increase in
total petroleum and natural gas sales which was partially offset by lower realized pricing which resulted in a $425.0 million
decrease in total petroleum and natural gas sales.
ROYALTIES
Royalties are paid to various government entities and to land and mineral rights owners. Royalties are calculated based on gross
revenues or on operating netbacks less capital investment for specific heavy oil projects and are generally expressed as a
percentage of total sales, net of blending and other expense. The actual royalty rates can vary depending on the commodity
produced, royalty contract terms, commodity price level, royalty incentives and the area or jurisdiction. The following table
summarizes our royalties and royalty rates for the years ended December 31, 2023 and 2022.
Years Ended December 31
2023
2022
($ thousands except for % and per boe)
Canada
U.S.
Total
Canada
U.S.
Total
Royalties
Average royalty rate (1)(2)
Royalties per boe (3)
$ 213,148
$ 456,644
$ 669,792
$ 277,428
$ 285,536
$ 562,964
14.2%
27.6%
21.2%
16.0%
29.7%
20.9%
$
9.55
$ 20.51
$ 15.02
$ 13.75
$ 27.70
$ 18.47
(1) Average royalty rate is calculated as royalties divided by total sales, net of blending and other expense.
(2) Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation
of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.
(3) Royalties per boe is calculated as royalties divided by barrels of oil equivalent production volume for the applicable period.
Royalties for 2023 were $669.8 million or 21.2% of total sales, net of blending and other expense, compared to $563.0 million or
20.9% in 2022. Total royalty expense was higher in 2023 due to higher total sales, net of blending and other expense, relative to
2022. Our average royalty rate of 21.2% for 2023 was higher than 20.9% for 2022 due to a higher proportion of our production
being from the Eagle Ford in 2023 which has a higher royalty rate than our Canadian properties. Our average royalty rate of 21.2%
for 2023 was consistent with expectations and our annual guidance range of 21.0% - 22.0% for 2023.
24
2023 / Annual Report / Baytex Energy
In Canada, the average royalty rate(1) was 14.2% in 2023 which was lower than 16.0% for 2022 and reflects lower benchmark
prices for our production in Canada. In the U.S., the average royalty rate was 27.6% for 2023 which is lower than 29.7% for 2022
due to production contributed by the acquired Ranger assets which have a lower royalty rate relative to our legacy non-operated
Eagle Ford properties.
We expect our average royalty rate to be approximately 23% for 2024 which reflects a higher proportion of our production from the
Eagle Ford in 2024 relative to 2023 with a full year of results including the Merger.
(1) Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation
of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.
OPERATING EXPENSE
Years Ended December 31
2023
2022
($ thousands except for per boe)
Operating expense
Operating expense per boe (1)
Canada
U.S.
Total
Canada
U.S.
Total
$ 368,605 $ 202,234 $ 570,839 $ 327,894 $
94,772 $ 422,666
$
16.51 $
9.08 $
12.80 $
16.25 $
9.19 $
13.86
(1) Operating expense per boe is calculated as operating expense divided by barrels of oil equivalent production volume for the applicable period.
Total operating expense was $570.8 million ($12.80/boe) in 2023 compared to $422.7 million ($13.86/boe) in 2022. Total operating
expense for 2023 increased relative to 2022 while per boe operating costs were lower as the Ranger properties have lower per boe
operating expenses. Operating expense of $12.80/boe for 2023 was consistent with our revised annual guidance of ~ $12.75/boe.
In Canada, operating expense was $368.6 million ($16.51/boe) for 2023 compared to $327.9 million ($16.25/boe) for 2022. The
total operating expenses were higher in Canada as a result of higher production while per boe operating costs in 2023 were
relatively consistent with 2022.
Our U.S. operating expense was $202.2 million ($9.08/boe) for 2023 compared to $94.8 million ($9.19/boe) for 2022. Total
operating expense in the U.S. was higher in 2023 relative to 2022 with the addition of production from the properties acquired from
Ranger. Per boe operating expense in the U.S., expressed in U.S. dollars, was US$6.73/boe for 2023 which is slightly lower than
US$7.06/boe for 2022 which reflects the lower per unit operating cost on the acquired operated Eagle Ford properties.
We expect annual operating expense of $11.25 - $12.00/boe for 2024 which reflects a higher proportion of our production from our
Eagle Ford properties relative to 2023, which have lower per unit operating costs.
TRANSPORTATION EXPENSE
Transportation expense includes the costs to move production to the sales point. The largest component of transportation expense
relates to the trucking of oil in Canada to pipeline and rail terminals which can vary depending on trucking rates and hauling
distances as we seek to optimize sales prices. Transportation expense in our U.S. operations reflects the costs incurred to deliver
our production to a centralized sales point via truck or pipeline.
The following table compares our transportation expense for the years ended December 31, 2023 and 2022.
Years Ended December 31
2023
2022
($ thousands except for per boe)
Transportation expense
Transportation expense per boe (1)
Canada
U.S.
Total
Canada
U.S.
Total
64,325 $
24,981 $
89,306 $
48,561 $
— $
48,561
2.88 $
1.12 $
2.00 $
2.41 $
— $
1.59
$
$
(1) Transportation expense per boe is calculated as transportation expense divided by barrels of oil equivalent production volume for the
applicable period.
Transportation expense was $89.3 million ($2.00/boe) for 2023 compared to $48.6 million ($1.59/boe) for 2022. In Canada, the
total transportation expense and per unit costs are higher in 2023 relative to 2022 as a result of additional heavy oil production
primarily at Peavine, along with higher trucking rates due to increased fuel surcharges and truck shortages. Transportation expense
in the U.S. is consistent with expectations for 2023 and reflects trucking and pipeline transportation costs on our Eagle Ford
operations acquired from Ranger.
Transportation expense of $2.00/boe in 2023 was slightly below our revised annual guidance of ~ $2.10/boe for 2023. We expect
annual transportation expense of $2.35 - $2.55/boe for 2024 which reflects a higher proportion of our 2024 production from the
Eagle Ford.
2023 / Annual Report / Baytex Energy 25
BLENDING AND OTHER EXPENSE
Blending and other expense primarily includes the cost of blending diluent purchased to reduce the viscosity of our heavy oil
transported through pipelines in order 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.
Blending and other expense was $224.8 million for 2023 compared to $189.5 million for 2022. The increase in blending and other
expense is primarily a result of higher heavy oil production and pipeline shipments in 2023 relative to 2022.
FINANCIAL DERIVATIVES
As part of our normal operations, we are exposed to movements in commodity prices, foreign exchange rates, interest rates and
changes in our share price. In an effort to manage these exposures, we utilize various financial derivative contracts which are
intended to partially reduce the volatility in our free cash flow. Contracts settled in the period result in realized gains or losses based
on the market price compared to the contract price and the notional volume outstanding. Changes in the fair value of unsettled
contracts are reported as unrealized gains or losses in the period as the forward markets fluctuate and as new contracts are
entered. The following table summarizes the results of our financial derivative contracts for the years ended December 31, 2023
and 2022.
($ thousands)
Realized financial derivatives gain (loss)
Crude oil
Natural gas
Total
Unrealized financial derivatives (loss) gain
Crude oil
Natural gas
Equity total return swap
Total
Total financial derivatives gain (loss)
Crude oil
Natural gas
Equity total return swap
Total
Years Ended December 31
2023
2022
Change
35,687 $
(299,788) $
525
(34,693)
36,212 $
(334,481) $
335,475
35,218
370,693
(17,674) $
136,879 $
(154,553)
6,157
—
5,082
(6,490)
1,075
6,490
(11,517) $
135,471 $
(146,988)
18,013 $
(162,909) $
180,922
6,682
—
(29,611)
(6,490)
36,293
6,490
24,695 $
(199,010) $
223,705
$
$
$
$
$
$
We recorded a financial derivatives gain of $24.7 million for 2023 compared to a loss of $199.0 million for 2022. The realized
financial derivatives gain for 2023 of $36.2 million was primarily a result of market prices for crude oil and natural gas settling at
levels below the prices set in our derivative contracts. The unrealized financial derivatives loss of $11.5 million for 2023 is primarily
due to changes in forecasted crude oil pricing used to revalue the volumes outstanding on our crude oil and natural gas contracts
in place at December 31, 2023 relative to December 31, 2022. The fair value of our financial derivative contracts resulted in a net
asset of $23.3 million at December 31, 2023 compared to a net asset of $10.1 million at December 31, 2022.
26
2023 / Annual Report / Baytex Energy
Baytex had the following commodity financial derivative contracts as at February 28, 2024.
Period
Volume
Price/Unit (1)
Oil
Basis differential
Jan 2024 to Jun 2024
4,000 bbl/d
Basis differential
July 2024 to Dec 2024
4,000 bbl/d
Basis differential (2)
July 2024 to Dec 2024
5,000 bbl/d
Basis differential (2)
Apr 2024 to Dec 2024
3,000 bbl/d
Baytex pays: WCS differential at
Hardisty
Baytex receives: WCS differential
at Houston less US$8.10/bbl
Baytex pays: WCS differential at
Hardisty
Baytex receives: WCS differential
at Houston less US$8.40/bbl
Baytex pays: WCS differential at
Hardisty
Baytex receives: WCS differential
at Houston less US$8.18/bbl
Baytex pays: WCS differential at
Hardisty
Baytex receives: WCS differential
at Houston less US$8.27/bbl
Basis differential (2)
Basis differential
Basis differential (2)
Basis differential (2)
Collar
Collar
Collar
Collar
Collar
Collar
Collar
Collar
Collar (2)
Collar (2)
Natural Gas
Fixed Sell
Collar
Collar
Collar
Collar
Collar
Collar
Collar
Natural Gas Liquids
Fixed Sell
July 2024 to Dec 2024
Jan 2024 to Dec 2024
3,000 bbl/d
1,500 bbl/d
WTI less US$13.70/bbl
WTI less US$2.65/bbl
Apr 2024 to Dec 2024
1,250 bbl/d
WTI less US$3.40/bbl
July 2024 to Dec 2024
2,500 bbl/d
WTI less US$2.85/bbl
Jan 2024 to Mar 2024
10,400 bbl/d
US$60.00/US$100.00
Jan 2024 to Jun 2024
24,500 bbl/d
US$60.00/US$100.00
July 2024 to Dec 2024
2,500 bbl/d
US$60.00/US$90.21
Apr 2024 to Jun 2024
11,750 bbl/d
US$60.00/US$100.00
July 2024 to Dec 2024
2,500 bbl/d
US$60.00/US$94.15
July 2024 to Dec 2024
10,000 bbl/d
US$60.00/US$100.00
July 2024 to Sep 2024
10,000 bbl/d
US$60.00/US$100.00
Oct 2024 to Dec 2024
2,500 bbl/d
US$60.00/US$100.00
July 2024 to Dec 2024
9,000 bbl/d
US$60.00/US$84.58
Oct 2024 to Dec 2024
7,000 bbl/d
US$60.00/US$86.43
Jan 2024 to Mar 2024
3,500 mmbtu/d
US$3.5025
Jan 2024 to Mar 2024
11,538 mmbtu/d
US$2.50/US$3.65
Apr 2024 to Jun 2024
11,538 mmbtu/d
US$2.33/US$3.00
Jan 2024 to Dec 2024
2,500 mmbtu/d
US$3.00/US$4.06
Jan 2024 to Dec 2024
2,500 mmbtu/d
US$3.00/US$4.09
Jan 2024 to Dec 2024
5,000 mmbtu/d
US$3.00/US$4.10
Jan 2024 to Dec 2024
8,500 mmbtu/d
US$3.00/US$4.15
Jan 2024 to Dec 2024
5,000 mmbtu/d
US$3.00/US$4.19
Index
WCS
WCS
WCS
WCS
WCS
MSW
MSW
MSW
WTI
WTI
WTI
WTI
WTI
WTI
WTI
WTI
WTI
WTI
NYMEX
NYMEX
NYMEX
NYMEX
NYMEX
NYMEX
NYMEX
NYMEX
Jan 2024 to Mar 2024
34,364 gallon/d
US$0.2280/gallon
Mt. Belvieu Non-
TET Ethane
(1) Based on the weighted average price per unit for the period.
(2) Contracts entered subsequent to December 31, 2023.
2023 / Annual Report / Baytex Energy 27
OPERATING NETBACK
The following table summarizes our operating netback on a per boe basis for our Canadian and U.S. operations for the years
ended December 31, 2023 and 2022.
($ per boe except for volume)
Total production (boe/d)
Canada
61,157
U.S.
Total
60,997
122,154
Canada
55,275
U.S.
Total
28,245
83,519
Years Ended December 31
2023
2022
Operating netback:
Total sales, net of blending and other expense (1) $
Less:
Royalties (2)
Operating expense (2)
Transportation expense (2)
Operating netback (1)
Realized financial derivatives gain (loss) (3)
Operating netback after financial derivatives (1)
$
$
67.39 $
74.27 $
70.82 $
86.10 $
93.36 $
88.56
(9.55)
(20.51)
(16.51)
(2.88)
(9.08)
(1.12)
(15.02)
(12.80)
(2.00)
(13.75)
(16.25)
(2.41)
(27.70)
(9.19)
—
(18.47)
(13.86)
(1.59)
38.45 $
43.56 $
41.00 $
53.69 $
56.47 $
54.64
—
—
0.81
—
—
(10.97)
38.45 $
43.56 $
41.81 $
53.69 $
56.47 $
43.67
(1) Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation
of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.
(2) Refer to Royalties, Operating Expense and Transportation Expense sections in this MD&A for a description of the composition these
measures.
(3) Calculated as realized financial derivatives gain or loss divided by barrels of oil equivalent production volume for the applicable period.
Our operating netback of $41.00/boe for 2023 was lower than $54.64/boe for 2022 due to lower benchmark pricing in Canada and
the U.S. which resulted in a decrease in per unit sales net of royalties. Total operating expense and transportation expense of
$14.80/boe was lower than $15.45/boe in 2022 which reflects lower operating and transportation costs on the operated Eagle Ford
properties acquired from Ranger. Including realized gains on financial derivatives, our operating netback was $41.81/boe for 2023
compared to $43.67/boe for 2022.
GENERAL AND ADMINISTRATIVE EXPENSE
General and administrative ("G&A") expense includes head office and corporate costs such as salaries and employee benefits,
public company costs and administrative recoveries earned for operating exploration and development activities on behalf of our
working interest partners. G&A expense fluctuates with head office staffing levels and the level of operated exploration and
development activity during the period.
The following table summarizes our G&A expense for the years ended December 31, 2023 and 2022.
($ thousands except for per boe)
Gross general and administrative expense
Overhead recoveries
General and administrative expense
General and administrative expense per boe (1)
Years Ended December 31
2023
84,096 $
(14,307)
69,789 $
1.57 $
$
$
$
2022
55,785 $
(5,515)
50,270 $
1.65 $
Change
28,311
(8,792)
19,519
(0.08)
(1) General and administrative expense per boe is calculated as general and administrative expense divided by barrels of oil equivalent
production volume for the applicable period.
G&A expense was $69.8 million ($1.57/boe) for 2023 compared to $50.3 million ($1.65/boe) for 2022. G&A expense was
$19.5 million higher relative to 2022 due to the increase in staffing levels and integration costs associated with the Merger with
Ranger. G&A expense of $69.8 million ($1.57/boe) for 2023 was lower than our revised annual guidance of $80 million ($1.80/boe).
We expect annual G&A expense of $92 million ($1.65/boe) for 2024 which reflects a full-year of staffing costs associated with the
personnel retained after the acquisition of Ranger.
28
2023 / Annual Report / Baytex Energy
FINANCING AND INTEREST EXPENSE
Financing and interest expense includes interest on our credit facilities, long-term notes and lease obligations as well as non-cash
financing costs which include the accretion on our debt issue costs and asset retirement obligations. Financing and interest
expense varies depending on debt levels outstanding during the period, the applicable borrowing rates, CAD/USD foreign
exchange rates, along with the carrying amount of asset retirement obligations and the discount rates used to present value these
obligations.
The following table summarizes our financing and interest expense for the years ended December 31, 2023 and 2022.
($ thousands except for per boe)
Interest on credit facilities
Interest on long-term notes
Interest on lease obligations
Cash interest
Amortization of debt issue costs
Accretion of asset retirement obligations
Early redemption expense
Financing and interest expense
Cash interest per boe (1)
Financing and interest expense per boe (1)
Years Ended December 31
2023
2022
56,713 $
19,550 $
102,426
684
60,643
193
159,823 $
80,386 $
11,944
20,406
—
6,286
15,683
2,462
192,173 $
104,817 $
3.58 $
4.31 $
2.64 $
3.44 $
$
$
$
$
$
Change
37,163
41,783
491
79,437
5,658
4,723
(2,462)
87,356
0.94
0.87
(1) Calculated as cash interest or financing and interest expense divided by barrels of oil equivalent production volume for the applicable period.
Financing and interest expense was $192.2 million ($4.31/boe) in 2023 compared to $104.8 million ($3.44/boe) in 2022. Higher
interest costs in 2023 relative to 2022 are primarily a result of the additional debt outstanding after the Merger with Ranger.
Cash interest of $159.8 million ($3.58/boe) in 2023 was higher than $80.4 million ($2.64/boe) in 2022 as a result of additional debt
outstanding in 2023 after the Merger which included the issuance of US$800.0 million aggregate principal amount of long-term
notes. Interest on our credit facilities was higher in 2023 relative to 2022 due to the increase in applicable borrowing rates along
with an increase in the principal amounts outstanding following the Merger. The weighted average interest rate applicable on our
credit facilities was 7.6% in 2023 compared to 3.6% in 2022.
Accretion of asset retirement obligations of $20.4 million for 2023 was higher than $15.7 million for 2022 primarily due to higher
discount rates in 2023 relative to 2022. Accretion of debt issues costs was higher in 2023 relative to 2022 due to the increase in
debt issue costs associated with the expanded credit facilities and new long-term notes issued to fund the Merger with Ranger.
Cash interest of $159.8 million ($3.58/boe) for 2023 was consistent with our revised annual guidance of $156 million ($3.50/boe).
We expect cash interest to be $190 million ($3.40/boe) for 2024.
EXPLORATION AND EVALUATION EXPENSE
Exploration and evaluation ("E&E") expense is related to the expiry of leases and the de-recognition of costs for exploration
programs that have not demonstrated commercial viability and technical feasibility. E&E expense will vary depending on the timing
of expiring leases, the accumulated costs of the expiring leases and the economic facts and circumstances related to the
Company's exploration programs. Exploration and evaluation expense was $8.9 million for 2023 compared to $30.2 million for
2022.
DEPLETION AND DEPRECIATION
Depletion and depreciation expense varies with the carrying amount of the Company's oil and gas properties, the amount of proved
and probable reserves volumes and the rate of production for the period. The following table summarizes depletion and
depreciation expense for the years ended December 31, 2023 and 2022.
($ thousands except for per boe)
Depletion and depreciation
Depletion and depreciation per boe(1)
Years Ended December 31
2023
2022
Change
$
$
1,047,904 $
587,050 $
460,854
23.50 $
19.26 $
4.24
(1) Depletion and depreciation expense per boe is calculated as depletion and depreciation expense divided by barrels of oil equivalent production
volume for the applicable period.
2023 / Annual Report / Baytex Energy 29
Depletion and depreciation expense was $1.0 billion ($23.50/boe) for 2023 compared to $587.1 million ($19.26/boe) for 2022. Total
depletion and depreciation expense as well as the depletion and depreciation rate per boe were higher in 2023 relative to 2022 due
to impairment reversals in Q4/2022 which increased the depletable base for our legacy assets in addition to depletion on the assets
acquired from Ranger which have a higher depletion rate than our other properties.
IMPAIRMENT
2023 Impairment
At December 31, 2023, we identified indicators of impairment for oil and gas properties in our legacy non-operated Eagle Ford
cash-generating unit ("CGU") due to changes in our reserves volumes and in our Viking CGU due to changes in reserves along
with a loss recorded on disposition of an asset within the CGU. The recoverable amounts for the two CGUs were not sufficient to
support their carrying values which resulted in an impairment of $833.7 million recorded at December 31, 2023.
At December 31, 2023, the recoverable amounts of the two CGUs were calculated using the following benchmark reference prices
for the years 2024 to 2033 adjusted for commodity differentials specific to the CGU. The prices and costs subsequent to 2033 have
been adjusted for inflation at an annual rate of 2.0%.
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
WTI crude oil (US$/bbl)
73.67
74.98
76.14
77.66
79.22
80.80
82.42
84.06
85.74
87.46
LLS crude oil (US$/bbl)
76.49
77.80
78.95
80.35
81.95
83.59
85.27
86.97
88.71
90.48
Edmonton par oil ($/bbl)
92.91
95.04
96.07
97.99
99.95 101.94 103.98 106.06 108.18 110.35
NYMEX Henry Hub gas (US$/
mmbtu)
AECO gas ($/mmbtu)
Exchange rate (CAD/USD)
2.75
2.20
0.75
3.64
3.37
0.75
4.02
4.05
0.76
4.10
4.13
0.76
4.18
4.21
0.76
4.27
4.30
0.76
4.35
4.38
0.76
4.44
4.47
0.76
4.53
4.56
0.76
4.62
4.65
0.76
The following table summarizes the recoverable amount and impairment for each of the two CGUs at December 31, 2023 and
demonstrates the sensitivity of the impairment to reasonably possible changes in key assumptions inherent in the calculation.
Recoverable
amount
Impairment loss Change in discount
rate of 1%
Change in oil price
of $2.50/bbl
Change in gas
price of $0.25/mcf
Viking CGU
Eagle Ford Non-op CGU (1)
$
606,290 $
184,000 $
1,429,658
649,662
26,500 $
71,300
53,000 $
107,600
3,500
25,700
(1) There were no indicators of impairment identified for the Eagle Ford Operated CGU which includes the assets acquired from Ranger.
2022 Impairment Reversal
At December 31, 2022, indicators of impairment reversal were identified for oil and gas properties in five CGUs due to the increase
in forecasted commodity prices in addition to changes in reserves volumes. The recoverable amount for three CGUs exceeded
their carrying values which resulted in an impairment reversal of $245.2 million recorded at December 31, 2022. At December 31,
2022, we identified indicators of impairment reversal for E&E assets in the Peace River CGU due to an increase in land sale values
and recorded an impairment reversal of $22.5 million. The total impairment reversal recorded at December 31, 2022 was $267.7
million.
The following table summarizes the recoverable amount and impairment reversal for each of the five CGUs at December 31, 2022
and demonstrates the sensitivity of the impairment reversal to reasonably possible changes in key assumptions inherent in the
calculation.
Recoverable
amount
Impairment
reversal
Change in discount
rate of 1%
Change in oil price
of $2.50/bbl
Change in gas
price of $0.25/mcf
Conventional CGU (1)
Peace River CGU (1)
Lloydminster CGU
Viking CGU
Eagle Ford Non-op CGU
$
119,031 $
23,707 $
676,939
449,250
1,322,193
2,102,646
140,534
—
81,000
—
— $
—
11,500
39,500
95,800
— $
—
53,000
78,000
131,100
—
—
—
4,000
28,500
(1) The impairment reversals for the Conventional and Peace River CGUs were limited to the total accumulated impairments less subsequent
depletion of $23.7 million and $140.5 million, respectively. As a result, changes in the key assumptions presented in the table above have no
impact on the amount of the impairment reversal as at December 31, 2022.
30
2023 / Annual Report / Baytex Energy
SHARE-BASED COMPENSATION EXPENSE
Share-based compensation ("SBC") expense includes expense associated with our Share Award Incentive Plan, Incentive Award
Plan, and Deferred Share Unit Plan. SBC expense associated with equity-classified awards is recognized in net income or loss
over the vesting period of the awards with a corresponding increase in contributed surplus. SBC expense associated with cash-
settled awards is recognized in net income or loss over the vesting period of the awards, with a corresponding financial liability
included in share-based compensation liability, and includes gains or losses on equity total return swaps. SBC expense varies with
the quantity of unvested share awards outstanding and changes in the market price of our common shares.
We recorded SBC expense of $37.7 million for 2023 compared to $29.1 million for 2022. SBC expense for 2023 includes cash
compensation expense of $21.5 million which is lower than $25.9 million for 2022. Lower cash SBC expense reflects a decrease in
our share price during 2023 along with a reduction of the notional amount of equity return swaps outstanding in 2023 compared to
2022. SBC expense for 2023 also includes non-cash compensation expense of $16.2 million related to awards assumed in
conjunction with the Merger which were settled in Baytex common shares.
Regular expensing of compensation awards is considered a cash expense as we intend to settle currently outstanding and future
awards in cash while Baytex is repurchasing shares as part of its shareholder return program. In Q1/2023 we reduced the notional
amount of the equity total return swaps to match the number of awards outstanding under the Deferred Share Unit Plan where we
previously had targeted an amount equivalent to approximately 90-100% of all cash settled awards outstanding.
FOREIGN EXCHANGE
Unrealized foreign exchange gains and losses are primarily a result of changes in the reported amount of our U.S. dollar
denominated long-term notes and credit facilities in our Canadian functional currency entities. The long-term notes and credit
facilities are translated to Canadian dollars on the balance sheet date using the closing CAD/USD exchange rate resulting in
unrealized gains and losses. Realized foreign exchange gains and losses are due to day-to-day U.S. dollar denominated
transactions occurring in our Canadian functional currency entities.
($ thousands except for exchange rates)
Unrealized foreign exchange (gain) loss
Realized foreign exchange loss (gain)
Foreign exchange (gain) loss
CAD/USD exchange rates:
At beginning of period
At end of period
$
$
Years Ended December 31
2023
(14,300) $
3,452
(10,848) $
1.3534
1.3205
2022
45,073 $
(1,632)
43,441 $
1.2656
1.3534
Change
(59,373)
5,084
(54,289)
We recorded a foreign exchange gain of $10.8 million for 2023 compared to a loss of $43.4 million for 2022.
The unrealized foreign exchange gain of $14.3 million for 2023 is primarily related to changes in the reported amount of our long-
term notes and credit facilities. The gain recorded in 2023 is due to a strengthening of the Canadian dollar relative to U.S. dollar at
December 31, 2023 compared to December 31, 2022 and June 20, 2023 when additional U.S. denominated debt was issued to
fund the Merger with Ranger. The unrealized foreign exchange loss of $45.1 million for 2022 relates to a weakening of the
Canadian dollar relative to the U.S. dollar at December 31, 2022 compared to December 31, 2021 and reflects the remeasurement
of our long-term notes and credit facilities.
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 $3.5 million for 2023
compared to a gain of $1.6 million for 2022.
INCOME TAXES
($ thousands)
Current income tax expense
Deferred income tax (recovery) expense
Total income tax (recovery) expense
Years Ended December 31
2023
14,403 $
(297,629)
(283,226) $
$
$
2022
3,594 $
31,716
35,310 $
Change
10,809
(329,345)
(318,536)
2023 / Annual Report / Baytex Energy 31
Current income tax expense was $14.4 million for 2023 compared to $3.6 million recorded in 2022. Current income tax is higher in
2023 due to higher tax owed on our U.S. operations following the Merger with Ranger. We recorded a deferred income tax
recovery of $297.6 million for 2023 compared to deferred tax expense of $31.7 million for 2022. The deferred tax recovery in 2023
is primarily related to the effects of the transaction structuring for the Merger in Q2/2023 along with the effects of impairment losses
on our Canadian and U.S. assets in 2023.
In June 2016, certain indirect subsidiary entities received reassessments from the Canada Revenue Agency ("CRA") that deny
non-capital loss deductions relevant to the calculation of income taxes for the years 2011 through 2015. Following objections and
submissions, in November 2023 the CRA issued notices of confirmation regarding their prior reassessments. In February 2024,
Baytex filed notices of appeal with the Tax Court of Canada and we estimate it could take between two and three years to receive a
judgment. The reassessments do not require us to pay any amounts in order to participate in the appeals process. Should we be
unsuccessful at the Tax Court of Canada, additional appeals are available; a process that we estimate could take another two
years and potentially longer.
We remain confident that the tax filings of the affected entities are correct and will defend our tax filing positions. We have also
purchased $272.5 million of insurance coverage for a premium of $50.3 million which will help manage the litigation risk associated
with this matter. The most recent reassessments issued by the CRA assert taxes owing by the trusts of $244.8 million, late
payment interest of $166.6 million as at the date of reassessments and a late filing penalty in respect of the 2011 tax year of $4.1
million.
By way of background, we acquired several privately held commercial trusts in 2010 with accumulated non-capital losses of
$591.0 million (the "Losses"). The Losses were subsequently deducted in computing the taxable income of those trusts. The
reassessments, as confirmed in November 2023, disallow the deduction of the Losses for two reasons. Firstly, the reassessments
allege that (i) the trusts were resettled, and (ii) the resulting successor trusts were not able to access the losses of the predecessor
trusts. Secondly, the reassessments allege that the general anti-avoidance rule of the Income Tax Act (Canada) operates to deny
the deduction of the losses. If, after exhausting available appeals, the deduction of Losses continues to be disallowed, either the
trusts or their corporate beneficiary will owe cash taxes, late payment interest and potentially penalties. The amount of cash taxes
owing, late payment interest and potential penalties are dependent upon the taxpayer(s) ultimately liable (the trusts or their
corporate beneficiary) and the amount of unused tax shelter available to those/that taxpayer(s) to offset the reassessed income,
including tax shelter from future years that may be carried back and applied to prior years.
The following table summarizes our Canadian and Foreign tax pools.
Canadian Tax Pools ($ thousands)
December 31, 2023
December 31, 2022
Canadian oil and natural gas property expenditures
$
203,406 $
518,788
280,564
643,697
98,816
355,028
483,270
275,987
818,326
62,442
$
1,745,271 $
1,995,053
1,893,577
352,021 $
213,372
2,558,472
468,554
139,013
—
14,483
813,753
96,157
$
5,485,996 $
1,063,406
Canadian development expenditures
Undepreciated capital costs
Non-capital losses
Financing costs and other
Total Canadian tax pools
Foreign Tax Pools ($ thousands)
Depletion
Intangible drilling costs
Tangibles
Net operating losses
Other
Total Foreign tax pools
32
2023 / Annual Report / Baytex Energy
NET (LOSS) INCOME AND ADJUSTED FUNDS FLOW
The components of adjusted funds flow and net income or loss for the years ended December 31, 2023 and 2022 are set forth in
the following table.
($ thousands)
Petroleum and natural gas sales
Royalties
Revenue, net of royalties
Expenses
Operating
Transportation
Blending and other
Operating netback (1)
General and administrative
Cash interest
Realized financial derivatives gain (loss)
Realized foreign exchange (loss) gain
Other expense
Current income tax expense
Cash share-based compensation
Adjusted funds flow (2)
Transaction costs
Exploration and evaluation
Depletion and depreciation
Non-cash share-based compensation
Non-cash financing and interest
Non-cash other income
Unrealized financial derivatives (loss) gain
Unrealized foreign exchange gain (loss)
(Loss) gain on dispositions
Impairment (loss) reversal
Deferred income tax recovery (expense)
Net (loss) income
Years Ended December 31
2023
2022
$
3,382,621 $
2,889,045 $
(669,792)
2,712,829
(562,964)
2,326,081
(570,839)
(89,306)
(224,802)
(422,666)
(48,561)
(189,454)
$
1,827,882 $
1,665,400 $
(69,789)
(159,823)
36,212
(3,452)
(815)
(14,403)
(21,462)
(50,270)
(80,386)
(334,481)
1,632
(7,253)
(3,594)
(25,897)
$
1,594,350 $
1,165,151 $
(49,045)
(8,896)
(1,047,904)
(16,237)
(32,350)
1,271
(11,517)
14,300
(141,295)
(833,662)
297,629
—
(30,239)
(587,050)
(3,159)
(24,431)
4,009
135,471
(45,073)
4,898
267,744
(31,716)
Change
493,576
(106,828)
386,748
(148,173)
(40,745)
(35,348)
162,482
(19,519)
(79,437)
370,693
(5,084)
6,438
(10,809)
4,435
429,199
(49,045)
21,343
(460,854)
(13,078)
(7,919)
(2,738)
(146,988)
59,373
(146,193)
(1,101,406)
329,345
$
(233,356) $
855,605 $
(1,088,961)
(1) Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation
of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.
(2) Capital management measure. Refer to the Specified Financial Measures section in this MD&A for further information.
We generated adjusted funds flow of $1.6 billion for 2023 compared to $1.2 billion for 2022. The $429.2 million increase in adjusted
funds flow for 2023 is due to higher production from the Merger with Ranger which was partially offset by lower commodity prices
and also resulted in a $370.7 million improvement in realized gains (losses) on financial derivatives.
We reported net loss of $233.4 million for 2023 compared to net income of $855.6 million for 2022. The decrease in net income for
2023 relative to 2022 is primarily a result of the $833.7 million impairment loss recorded in 2023 compared to the $267.7 million
impairment reversal recorded in 2022 and a $460.9 million increase in depletion and depreciation expense as a result of the oil and
gas properties acquired from Ranger. The decrease in net income was partially offset by a $329.3 million decrease in deferred
income tax expense primarily related to the effects of the transaction structuring for the Merger.
2023 / Annual Report / Baytex Energy 33
OTHER COMPREHENSIVE (LOSS) INCOME
Other comprehensive (loss) income is comprised of the foreign currency translation adjustment on U.S. net assets which is not
recognized in net income or loss. The foreign currency translation loss of $65.3 million for 2023 relates to the change in value of
our U.S. net assets and is due to the strengthening of the Canadian dollar relative to the U.S. dollar at December 31, 2023
compared to December 31, 2022 and June 20, 2023 when we completed the Merger with Ranger. The CAD/USD exchange rate
was 1.3205 CAD/USD at December 31, 2023 compared to 1.32485 CAD/USD at June 20, 2023 and 1.3534 CAD/USD at
December 31, 2022.
CAPITAL EXPENDITURES
Capital expenditures for the years ended December 31, 2023 and 2022 are summarized as follows.
Years Ended December 31
2023
2022
($ thousands)
Canada
U.S.
Total
Canada
U.S.
Total
Drilling, completion and equipping
$
393,127 $
492,030 $
885,157 $
321,836 $
136,746 $
458,582
Facilities
Land, seismic and other
Exploration and development
expenditures
Property acquisitions
46,225
23,846
42,167
15,392
88,392
39,238
32,573
26,393
3,151
843
35,724
27,236
$
463,198 $
549,589 $ 1,012,787 $
380,802 $
140,740 $
521,542
20,023
18,891
38,914
1,352
—
1,352
Proceeds from dispositions
$
(160,256) $
— $
(160,256) $
(25,649) $
— $
(25,649)
Exploration and development expenditures were $1.0 billion for 2023 compared to $521.5 million for 2022. Exploration and
development expenditures for 2023 reflect increased development activity in Canada along with development activity on the
properties acquired from Ranger after the Merger closed on June 20, 2023.
In Canada, exploration and development expenditures were $463.2 million in 2023 which is $82.4 million higher than $380.8 million
in 2022. Drilling and completion spending of $393.1 million in 2023 reflects higher light and heavy oil development activity relative
to 2022 when we spent $321.8 million. We also invested $46.2 million on facilities, $23.8 million on land, seismic and other
expenditures and completed a non-core property disposition of certain Viking assets for proceeds of $159.7 million, including
closing adjustments.
Total U.S. exploration and development expenditures were $549.6 million for 2023 which is $408.8 million higher than
$140.7 million for 2022. Exploration and development activity for 2023 reflects expenditures for development activity on our
operated properties after closing of the Merger on June 20, 2023 along with additional activity on our non-operated properties in the
Eagle Ford.
Total exploration and development expenditures of $1.0 billion for 2023 were consistent with our revised annual guidance of
approximately $1.0 billion. We expect annual exploration and development expenditures of $1.2 - $1.3 billion for 2024.
CAPITAL RESOURCES AND LIQUIDITY
Our capital management objective is to maintain a strong balance sheet that provides financial flexibility to execute our
development programs, provide returns to shareholders and optimize our portfolio through strategic acquisitions. We strive to
actively manage our capital structure in response to changes in economic conditions. At December 31, 2023, our capital structure
was comprised of shareholders' capital, long-term notes, trade receivables, prepaids and other assets, trade payables, dividends
payable, share-based compensation liability, other long-term liabilities, cash and the credit facilities.
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.
34
2023 / Annual Report / Baytex Energy
We are committed to maintaining a strong balance sheet. Upon reaching a total debt(1) target of $1.5 billion we intend to direct 75%
of free cash flow(2) to shareholder returns. At December 31, 2023, net debt(3) of $2.5 billion was $1.5 billion higher than $1.0 billion
at December 31, 2022. The increase in net debt for 2023 is primarily due to $732.8 million of cash consideration paid and the
assumption of $1.1 billion of net debt assumed in conjunction with the Merger. The cash portion of the transaction was funded with
Baytex’s expanded US$1.1 billion credit facility, a US$150 million two-year term loan facility which was repaid in August 2023 along
with the net proceeds from the issuance of US$800 million senior unsecured notes due 2030. Baytex closed the US$800 million
principal amount senior unsecured note offering on April 27, 2023 with the proceeds released from escrow at completion of the
Merger. As of December 31, 2023 we have reduced net debt by $280.6 million since closing the Merger on June 20, 2023.
In June 2023, we renewed our normal course issuer bid ("NCIB") and began repurchasing our common shares in July 2023 as part
of our shareholder return framework. As of December 31, 2023, we repurchased 40.5 million common shares at an average price
of $5.48 per share for total consideration of $221.9 million.
Our shareholder returns framework includes a quarterly dividend. On October 2, 2023 and January 2, 2024, we paid a quarterly
cash dividend of CDN$0.0225 per share to shareholders of record. On February 28, 2024, the Company's Board of Directors
declared a quarterly cash dividend of $0.0225 per share to be paid on April 1, 2024 for shareholders on record as at March 15,
2024. These dividends are designated as “eligible dividends” for Canadian income tax purposes. For U.S. income tax purposes,
Baytex’s dividends are considered “qualified dividends.”
(1) Calculated in accordance with our amended credit facilities agreement which is available on SEDAR+ at www.sedarplus.com.
(2) Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation
of similar measures presented by other entities. Refer to the Specified Financial Measures section for further information.
(3) Capital management measure. Refer to the Specified Financial Measures section in this MD&A for further information.
Credit Facilities
At December 31, 2023, we had $864.7 million of principal amount outstanding under our revolving credit facilities which total
US$1.1 billion ($1.5 billion) (the "Credit Facilities").
On June 20, 2023, we amended our Credit Facilities to facilitate the cash consideration paid in conjunction with the Merger and to
assume Ranger's net debt. The Credit Facilities were increased to US$1.1 billion and mature on April 1, 2026. The Credit Facilities
are secured and are comprised of a US$50 million operating loan and a US$750 million syndicated revolving loan for Baytex and a
US$45 million operating loan and a US$255 million syndicated revolving loan for Baytex's wholly-owned subsidiary, Baytex Energy
USA, Inc.
There are no mandatory principal payments required prior to maturity which could be extended upon our request. The Credit
Facilities contain standard commercial covenants in addition to the financial covenants detailed below. Advances 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 secured overnight financing rates ("SOFR"), plus applicable margins.
The weighted average interest rate on the Credit Facilities was 7.6% for 2023 as compared to 3.6% for 2022. The interest rate on
our Credit Facilities has increased due to an increase in the margins applicable to our Credit Facilities along with higher
government benchmark rates in 2023 relative to 2022.
As at December 31, 2023, Baytex had $5.6 million of outstanding letters of credit, $4.7 million of which is under a $20 million
uncommitted unsecured demand revolving letter of credit facility (December 31, 2022 - $15.7 million outstanding). Letters of credit
under this facility are guaranteed by Export Development Canada and do not use capacity available under the Credit Facilities.
The agreements and associated amending agreements relating to the Credit Facilities are accessible on the SEDAR+ website at
www.sedarplus.com and through the U.S. Securities and Exchange Commission at www.sec.gov.
2023 / Annual Report / Baytex Energy 35
Financial Covenants
The following table summarizes the financial covenants applicable to the Credit Facilities and our compliance therewith at
December 31, 2023.
Covenant Description
Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio)
Interest Coverage (3) (Minimum Ratio)
Total Debt (4) to Bank EBITDA (2) (Maximum Ratio)
Position as at
December 31, 2023
0.4:1.0
11.3:1.0
1.1:1.0
Covenant
3.5:1.0
3.5:1.0
4.0:1.0
(1)
(2)
(3)
(4)
"Senior Secured Debt" is calculated in accordance with the credit facility agreement and is defined as the principal amount of the credit
facilities and other secured obligations identified in the credit facility agreement. As at December 31, 2023, the Company's Senior Secured
Debt totaled $864.7 million.
"Bank EBITDA" is calculated based on terms and definitions set out in the credit facility agreement which adjusts net income or loss for
financing and interest expenses, income tax, non-recurring losses, certain specific unrealized and non-cash transactions 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, 2023 was $2.2 billion.
"Interest coverage" is calculated in accordance with the credit facility agreement and is computed as the ratio of Bank EBITDA to financing and
interest expenses, excluding certain non-cash transactions, and is calculated on a trailing twelve-month basis. Financing and interest
expenses for the twelve months ended December 31, 2023 were $195.2 million.
"Total Debt" is calculated in accordance with the credit facility agreement and is defined as all obligations, liabilities, and indebtedness of
Baytex excluding trade payables, other long-term liabilities, dividends payable, share-based compensation liability, asset retirement
obligations, leases, deferred income tax liabilities, and financial derivative liabilities. At December 31, 2023 our Total Debt was $2.5 billion.
Long-Term Notes
We have two issuances of long-term notes outstanding with a total principal amount of $1.6 billion as at December 31, 2023. The
long-term notes do not contain any financial maintenance covenants.
On February 5, 2020, we issued US$500 million aggregate principal amount of senior unsecured notes due April 1, 2027 bearing
interest at a rate of 8.75% per annum payable semi-annually (the "8.75% Senior Notes"). The 8.75% Senior Notes are redeemable
at our option, in whole or in part, at specified redemption prices after April 1, 2023 and will be redeemable at par from April 1, 2026
to maturity. At December 31, 2023 there was US$409.8 million aggregate principal amount of the 8.75% Senior Notes outstanding.
On April 27, 2023, we issued US$800 million aggregate principal amount of senior unsecured notes due April 30, 2030 bearing
interest at a rate of 8.50% per annum semi-annually (the "8.50% Senior Notes"). The 8.50% Senior Notes were issued at 98.709%
of par and are redeemable at our option, in whole or in part, at specified redemption prices after April 30, 2026 and will be
redeemable at par from April 30, 2028 to maturity. Net proceeds of $1.0 billion reflects $13.7 million for the original issue discount
and transaction costs of $18.5 million incurred with the issuance.
36
2023 / Annual Report / Baytex Energy
Shareholders’ Capital
We are authorized to issue an unlimited number of common shares and 10.0 million preferred shares. The rights and terms of
preferred shares are determined upon issuance. During the year ended December 31, 2023, we issued 311.4 million common
shares on closing of the Merger with Ranger in addition to 5.9 million common shares to settle awards outstanding in conjunction
with the Merger. As at February 28, 2024, we had 821.7 million common shares issued and outstanding and no preferred shares
issued and outstanding.
Contractual Obligations
We have a number of financial obligations that are incurred in the ordinary course of business. A significant portion of these
obligations will be funded by adjusted funds flow. These obligations as of December 31, 2023 and the expected timing for funding
these obligations are noted in the table below.
($ thousands)
Total
Less than
1 year
1-3 years
3-5 years Beyond 5 years
Credit Facilities - principal
$
864,736 $
— $
864,736 $
— $
—
Long-term notes - principal
Interest on long-term notes (1)
Lease obligations - principal (2)
Processing agreements
Transportation agreements
1,597,475
722,732
37,553
5,642
212,400
—
137,138
15,722
618
52,691
—
274,276
10,415
1,003
94,866
541,114
191,515
7,128
563
47,601
1,056,361
119,803
4,288
3,458
17,242
Total
$
3,440,538 $
206,169 $
1,245,296 $
787,921 $
1,201,152
(1) Excludes interest on Credit Facilities as interest payments on Credit Facilities fluctuate based on amounts outstanding and the prevailing
interest rate at the time of borrowing.
Includes leases which are committed to that have not yet commenced as at December 31, 2023.
(2)
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. The present value of the future estimated abandonment and reclamation costs are included in the asset
retirement obligations presented in the statement of financial position. Programs to abandon and reclaim well sites and facilities are
undertaken regularly in accordance with applicable legislative requirements.
2023 / Annual Report / Baytex Energy 37
FOURTH QUARTER OPERATING AND FINANCIAL RESULTS
($ thousands except for per boe)
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) (1)
Heavy oil, net of blending and other expense ($/bbl) (2)
NGL ($/bbl) (1)
Natural gas ($/mcf) (1)
Total sales, net of blending and other per boe (2)
Royalties per boe (3)
Operating expense per boe (3)
Transportation expense per boe (3)
Operating netback per boe (2)
Financial
Three Months Ended December 31
2023
2022
Canada
U.S.
Total
Canada
U.S.
Total
14,143
39,569
2,937
56,649
48,573
64,744
55,981
—
20,223
76,204
116,548
95,629
70,124
39,569
23,160
132,853
165,121
160,373
14,511
32,819
1,958
49,288
45,953
56,946
17,594
—
5,703
23,297
39,726
29,918
32,105
32,819
7,661
72,585
85,679
86,864
$
99.93 $
105.83 $
104.64 $
108.21 $
114.64 $
111.73
62.48
27.38
2.40
63.06
(9.69)
(15.61)
(3.02)
—
26.68
3.07
71.34
(19.42)
(8.17)
(1.33)
62.48
26.76
2.87
68.00
(15.49)
(11.17)
(2.02)
64.06
39.68
5.38
70.20
(10.06)
(15.98)
(2.83)
—
38.36
6.93
83.94
(25.06)
(7.48)
—
64.06
38.70
6.10
74.93
(15.23)
(13.06)
(1.85)
$
34.74 $
42.42 $
39.32 $
41.33 $
51.40 $
44.79
Petroleum and natural gas sales
$
437,889 $
627,626 $ 1,065,515 $
417,952 $
231,034 $
648,986
Royalties
Revenue, net of royalties
Operating
Transportation
Blending and other
Operating netback (2)
General and administrative
Cash interest
Realized financial derivatives gain (loss)
Other
Adjusted funds flow (4)
Net (loss) income
Exploration and development expenditures
Property acquisitions
Proceeds from dispositions
Net debt (4)
(57,746)
(170,824)
(228,570)
(52,718)
(68,973)
(121,691)
380,143
456,802
836,945
365,234
162,061
527,295
(93,006)
(18,005)
(62,296)
(71,867)
(164,873)
(11,739)
—
(29,744)
(62,296)
(83,742)
(14,817)
(50,174)
(20,593)
(104,335)
—
—
(14,817)
(50,174)
$
206,836 $
373,196 $
580,032 $
216,501 $
141,468 $
357,969
—
—
—
—
—
—
—
—
(22,280)
(56,698)
12,377
(11,283)
—
—
—
—
—
—
—
—
(14,945)
(19,711)
(49,665)
(18,096)
206,836 $
373,196 $
502,148 $
216,501 $
141,468 $
255,552
(255,238) $
(531,505) $
(625,830) $
366,104 $
88,480 $
352,807
75,137 $
124,077 $
199,214 $
85,641 $
17,993 $
103,634
$
$
$
15,032
18,891
33,923
1,085
$
(159,745) $
— $
(159,745) $
(148) $
—
— $
1,085
(148)
$ 2,534,287
987,446
(1) Calculated as light oil and condensate, NGL or natural gas sales divided by barrels of oil equivalent production volume for the applicable
period.
(2) Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation
of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.
(3) Calculated as royalties expense, operating expense or transportation expense divided by barrels of oil equivalent production volume for the
applicable period.
(4) Capital management measure. Refer to the Specified Financial Measures section in this MD&A for further information.
38
2023 / Annual Report / Baytex Energy
Benchmark Averages
WTI oil (US$/bbl) (1)
MEH oil (US$/bbl) (2)
MEH oil differential to WTI (US$/bbl)
Edmonton par oil ($/bbl) (3)
Edmonton par oil differential to WTI (US$/bbl)
WCS heavy oil ($/bbl) (4)
WCS heavy oil differential to WTI (US$/bbl)
AECO natural gas price ($/mcf) (5)
NYMEX natural gas price (US$/mmbtu) (6)
CAD/USD average exchange rate
Three Months Ended December 31
2023
78.32
80.62
2.30
99.72
(5.10)
76.86
(21.88)
2.66
2.88
1.3619
2022
Change
82.64
85.88
3.24
109.57
(1.94)
77.37
(25.65)
5.58
6.26
1.3577
(4.32)
(5.26)
(0.94)
(9.85)
(3.16)
(0.51)
3.77
(2.92)
(3.38)
0.0042
(1) WTI refers to the arithmetic average of NYMEX prompt month WTI for the applicable period.
(2) MEH refers to arithmetic average of the Argus WTI Houston differential weighted index price for the applicable period.
(3) Edmonton par refers to the average posting price for the benchmark MSW crude oil.
(4) WCS refers to the average posting price for the benchmark WCS heavy oil.
(5) AECO refers to the AECO arithmetic average month-ahead index price published by the Canadian Gas Price Reporter ("CGPR").
(6) NYMEX refers to the NYMEX last day average index price as published by the CGPR.
Our operating and financial results for Q4/2023 reflect the successful execution of our 2023 development programs in the U.S. and
Canada. We invested $199.2 million on exploration and development expenditures in Q4/2023 and delivered production of 160,373
boe/d. Free cash flow(1) was $290.8 million in Q4/2023 which reflects the disciplined execution of our development programs.
In Canada, production averaged 64,744 boe/d in Q4/2023 which was 7,798 boe/d higher than 56,946 boe/d reported for Q4/2022
as a result of our successful Clearwater development program at Peavine and our light oil Duvernay development. Lower
benchmark pricing resulted in a realized price of $63.06/boe for Q4/2023 which was $7.14/boe lower than $70.20/boe for Q4/2022.
The Edmonton Par benchmark averaged $99.72/bbl for Q4/2023 compared to $109.57/bbl for Q4/2022 and the WCS heavy oil
benchmark was $76.86/bbl in Q4/2023 compared to $77.37/bbl for the same period of 2022. Lower commodity prices were the
main factor that resulted in an operating netback(1) of $206.8 million ($34.74/boe) for Q4/2023 which was $9.7 million ($6.60/boe)
lower than $216.5 million ($41.33/boe) reported for Q4/2022. Exploration and development expenditures were $75.1 million in
Q4/2023 compared to $85.6 million in Q4/2022.
In the U.S., production averaged 95,629 boe/d for Q4/2023 which is 65,711 boe/d higher than 29,918 boe/d reported for Q4/2022
reflecting the production contribution from the Merger with Ranger. The MEH benchmark averaged US$80.62/bbl in Q4/2023 which
was US$5.26/boe lower than US$85.88/bbl during Q4/2022 and resulted in a realized price of $71.34/boe which was $12.60/boe
lower than our realized price of $83.94/boe in Q4/2022. Operating netback of $373.2 million ($42.42/boe) was $231.7 million
($8.98/boe) higher than $141.5 million ($51.40/boe) for Q4/2022 which reflects lower benchmark commodity prices and the
additional production following the acquisition of operated Eagle Ford properties as part of the Merger. Activity on the acquired
lands resulted in exploration and development expenditures of $124.1 million in Q4/2023 which were higher compared to Q4/2022
when we spent $18.0 million.
(1) Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation
of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.
2023 / Annual Report / Baytex Energy 39
We generated adjusted funds flow(1) of $502.1 million in Q4/2023 which is $246.6 million higher than $255.6 million in Q4/2022.
The increase in adjusted funds flow for Q4/2023 reflects higher production after the acquisition of operated Eagle Ford properties
as part of the Merger with Ranger along with lower commodity prices relative to Q4/2022. The production contribution from the
properties acquired from Ranger was the primary factor for the increase in production of 160,373 boe/d in Q4/2023 compared to
86,864 boe/d for Q4/2022. Higher production resulted in an operating netback(2) of $580.0 million for Q4/2023 which was $222.1
million higher than the same period of 2022 despite lower commodity prices that resulted in operating netback(2) of $39.32/boe for
Q4/2023 which was $5.47/boe lower than $44.79/boe in Q4/2022. We recorded realized financial derivatives gains of $12.4 million
in Q4/2023 compared to losses of $49.7 million in Q4/2022. G&A expense of $22.3 million in Q4/2023 was higher than $14.9
million in Q4/2022 due to additional administrative costs and staff retention required for the operation of the properties acquired
from Ranger. Interest expense of $56.7 million in Q4/2023 was $37.0 million higher than $19.7 million for Q4/2022 which reflects
the additional debt outstanding as a result of the Merger with Ranger in addition to an increase in interest rates during 2023. Net
debt(1) was $2.5 billion at Q4/2023 compared to $1.0 billion in Q4/2022.
We recorded a net loss of $625.8 million in Q4/2023 compared to net income of $352.8 million in Q4/2022. The decrease in net
income for Q4/2023 relative to Q4/2022 is primarily a result of the $833.7 million impairment loss recorded in Q4/2023 due to
changes in reserves volumes and the loss on a disposition within the Viking CGU, compared to $267.7 million of impairment
reversals recorded in Q4/2022, as well as an increase in depletion and depreciation expense as a result of the oil and gas
properties acquired from Ranger.
(1) Capital management measure. Refer to the Specified Financial Measures section in this MD&A for further information.
(2) Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation
of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.
40
2023 / Annual Report / Baytex Energy
QUARTERLY FINANCIAL INFORMATION
($ thousands, except per common share
amounts)
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
Petroleum and natural gas sales
1,065,515 1,163,010
598,760
555,336
648,986
712,065
854,169
673,825
2023
2022
Net (loss) income
Per common share - basic
Per common share - diluted
Adjusted funds flow (1)
Per common share - basic
Per common share - diluted
Free cash flow (2)
Per common share - basic
Per common share - diluted
(625,830)
127,430
213,603
51,441
352,807
264,968
180,972
56,858
(0.75)
(0.75)
0.15
0.15
0.37
0.36
0.09
0.09
0.65
0.64
0.48
0.47
0.32
0.32
0.10
0.10
502,148
581,623
273,590
236,989
255,552
284,288
345,704
279,607
0.60
0.60
0.68
0.68
0.47
0.47
0.43
0.43
0.47
0.46
0.51
0.51
0.61
0.60
0.49
0.49
290,785
158,440
96,313
(1,918)
143,324
111,568
245,316
121,318
0.35
0.35
0.19
0.18
0.17
0.16
—
—
0.26
0.26
0.20
0.20
0.43
0.43
0.21
0.21
Cash flows from operating activities
474,452
444,033
192,308
184,938
303,441
310,423
360,034
198,974
Per common share - basic
Per common share - diluted
Dividends declared
Per common share – basic
Per common share – diluted
0.57
0.57
0.52
0.52
18,381
19,138
0.02
0.02
0.02
0.02
0.33
0.33
—
—
—
0.34
0.34
—
—
—
0.56
0.55
—
—
—
0.56
0.56
—
—
—
0.63
0.63
—
—
—
0.35
0.35
—
—
—
Exploration and development expenditures
199,214
409,191
170,704
233,626
103,634
167,453
96,633
153,822
Canada
U.S.
Property acquisitions
Proceeds from dispositions
Net debt (1)
Total assets (3)
Common shares outstanding
Daily production
Total production (boe/d)
Canada (boe/d)
U.S. (boe/d)
Benchmark prices
WTI oil (US$/bbl)
WCS heavy ($/bbl)
Edmonton Light ($/bbl)
CAD/USD avg exchange rate
AECO gas ($/mcf)
NYMEX gas (US$/mmbtu)
Total sales, net of blending and other
expense ($/boe) (2)
Royalties ($/boe) (4)
Operating expense ($/boe) (4)
Transportation expense ($/boe) (4)
Operating netback ($/boe) (2)
Financial derivatives gain (loss) ($/boe) (4)
Operating netback after financial
derivatives ($/boe) (2)
75,137
107,053
96,403
184,606
85,641
117,150
51,881
126,130
124,077
302,138
74,301
49,020
17,993
50,303
44,752
27,692
33,923
(159,745)
4,277
(226)
(62)
(50)
506
(235)
1,085
—
(148)
(25,460)
208
(14)
59
(27)
2,534,287 2,824,348 2,814,844
995,170
987,446 1,113,559 1,123,297 1,275,680
7,460,931 8,946,181 8,617,444 5,180,059 5,103,769 4,923,617 4,870,432 4,917,811
821,681
845,360
862,192
545,553
544,930
547,615
560,139
569,214
160,373
150,600
64,744
95,629
63,289
87,311
89,761
55,874
33,887
86,760
60,651
26,109
86,864
56,946
29,918
83,194
55,803
27,391
83,090
54,919
28,170
80,867
53,385
27,482
78.32
76.86
99.72
1.3619
2.66
2.88
68.00
(15.49)
(11.17)
(2.02)
39.32
0.84
82.26
93.02
107.93
1.3410
2.39
2.55
80.34
(17.33)
(12.57)
(2.02)
48.42
73.78
78.85
95.13
76.13
69.44
99.04
1.3431
1.3520
2.35
2.10
4.34
3.42
66.82
(13.21)
(14.62)
(1.78)
37.21
63.48
(11.94)
(14.40)
(2.18)
34.96
0.15
2.00
0.69
82.64
77.37
109.57
1.3577
5.58
6.26
74.93
(15.23)
(13.06)
(1.85)
44.79
(6.21)
91.56
93.62
116.79
1.3059
5.81
8.20
108.41
122.05
137.79
1.2766
6.27
7.17
87.68
105.44
(19.21)
(14.39)
(1.67)
52.41
(22.69)
(14.21)
(1.56)
66.98
94.29
100.99
115.66
1.2661
4.59
4.95
86.89
(16.86)
(13.85)
(1.27)
54.91
(9.98)
(16.41)
(11.59)
40.16
48.57
39.21
35.65
38.58
42.43
50.57
43.32
(1) Capital management measure. Refer to the Specified Financial Measures section in this MD&A for further information.
(2) Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation
of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.
(3) Previously disclosed amounts have been revised to conform with current period presentation.
(4) Calculated as royalties expense, operating expenses, transportation expense or financial derivatives gain or loss divided by barrels of oil
equivalent production volume for the applicable period.
2023 / Annual Report / Baytex Energy 41
Our results for the previous eight quarters reflect the disciplined execution of our capital programs while oil and natural gas prices
have fluctuated. Production steadily increased from 80,867 boe/d in Q1/2022 to 160,373 boe/d in Q4/2023 which reflects strong
well performance from our development programs in Canada and the U.S. along with the production contribution from the Merger
with Ranger which closed on June 20, 2023.
Commodity prices strengthened to multi-year highs in 2022 following Russia's invasion of Ukraine which created elevated
uncertainty surrounding the global supply of oil and natural gas. The impact of increased commodity prices is reflected in our
realized price of $105.44/boe for Q2/2022 which is our strongest realized pricing in the most recent eight quarters. Our Q4/2023
realized price of $68.00/boe reflects recent declines in crude oil prices as global supply growth has resulted in a more balanced
market.
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(1) of $502.1 million for Q4/2023 reflects strong production results from our
development plans in the U.S. and Canada in addition to the Merger partially offset by declining price realizations.
Net debt can fluctuate 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. The increase in net debt(1)
from $1.3 billion at Q1/2022 to $2.5 billion at Q4/2023 is primarily a result of the Merger which closed in Q2/2023 along with $418.4
million of shareholder returns. Since closing the Merger in Q2/2023 we have reduced net debt by $280.6 million which
demonstrates our priority to maintain a strong balance sheet. The change in net debt also reflects free cash flow(2) of $1.2 billion
generated over the last eight quarters.
(1) Capital management measure. Refer to the Specified Financial Measures section in this MD&A for further information.
(2) Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation
of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.
ENVIRONMENTAL REGULATIONS
As a result of our involvement in the exploration for and production of oil and natural gas we are subject to various emissions,
carbon and other environmental regulations. Refer to the Risk Factors section of this MD&A for a full description of the risks
associated with these regulations and how they may impact our business in the future. In addition to the Risk Factors discussed in
this MD&A, additional information related to our emissions and sustainability initiatives is available on our website.
Reporting Regulations
In June 2023, the International Sustainability Standards Board ("ISSB") issued IFRS S1 General Requirements for Disclosure of
Sustainability-related Financial Information and IFRS S2 Climate-related Disclosures which are effective for annual reporting
periods beginning on or after January 1, 2024. These standards provide for transition relief in IFRS S1 that allow reporting entity to
report on only climate-related risks and opportunities in the first year of reporting under the sustainability standards.
The Canadian Securities Administrators ("CSA") are responsible for determining the reporting requirements for public companies in
Canada and are responsible for decisions related to the adoption of the sustainability disclosure standard, including the effective
annual reporting dates. The CSA issued proposed National Instrument NI-51-107 – Disclosure of Climate-related Matters in
October 2021. The CSA intends to consider the ISSB standards in addition to developments in United States reporting
requirements in its decision relating to development of climate-related disclosure requirements for Canadian reporting issuers. The
CSA will involve the Canadian Sustainability Standards Board ("CSSB") for a combined review of the suitability of the adopting the
ISSB standards in Canada. There is no requirement for public companies in Canada to adopt the ISSB standards until the CSA and
CSSB have issued a decision on reporting requirements in Canada. While we are actively reviewing the ISSB standards we have
not yet determined the impact on future financial statements nor have we quantified the costs to comply with such standards.
OFF BALANCE SHEET TRANSACTIONS
We do not have any financial arrangements that are excluded from the consolidated financial statements as at December 31, 2023,
nor are any such arrangements outstanding as of the date of this MD&A.
42
2023 / Annual Report / Baytex Energy
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, including
considerations related to various regulatory and legislative requirements, to the Company at the time of financial statement
preparation. Actual results could be materially different from those estimates as the effect of future events cannot be determined
with certainty. Revisions to estimates are recognized prospectively. 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, evaluating
the recoverability of deferred income tax assets and in the determination of recoverable 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 qualified reserves evaluators and represent the estimated recoverable quantities of oil, natural
gas and NGL reserves and the related 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 reserves and the related cash flows are based on a number of
factors and assumptions. Changes to estimates and assumptions such as forecasted commodity prices, production volumes,
capital and operating costs and royalty obligations could have a significant impact on reported reserves. Other estimates include
ultimate reserve recovery, marketability of oil and natural gas and other geological, economic and technical factors. Changes in the
Company's reserves estimates can have a significant impact on the calculation of depletion, the recoverability of deferred income
tax assets and in the determination of recoverable value estimates for non-financial assets.
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. The determination of the fair value assigned to assets acquired and liabilities assumed
requires management to make assumptions and estimates. These 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. The determination of
the acquisition-date fair value measurement of oil and gas properties acquired represents the largest fair value estimate which is
derived from the present value of expected cash flows associated with estimated acquired proved and probable oil and gas
reserves prepared by an independent qualified reserve evaluator using assumptions as outlined under "reserves", on an after-tax
basis and applying a discount rate. Assumptions used to arrive at the fair value of oil and gas properties are further verified by way
of market comparisons and third party sources.
Cash-generating Units
The Company's oil and gas properties are aggregated into CGUs which are the smallest identifiable group of assets that generates
cash inflows that are largely independent of the cash inflows 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. These indicators can be internal such as changes in
estimated proved and probable oil and gas reserves ("CGU reserves") and internally estimated oil and gas resources, or external
such as market conditions impacting discount rates or market capitalization. The assessment for each CGU considers significant
changes in the forecasted cash flows including reservoir performance, the number of development locations and timing of
development, forecasted commodity prices, production volumes, capital and operating costs and royalty obligations.
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 and probable oil and gas reserves and the discount rate
used to present value future cash flows. Any changes to these estimates and assumptions could impact the calculation of the
recoverable amount and the carrying value of assets.
2023 / Annual Report / Baytex Energy 43
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 risk-free discount rates and inflation
rates. The Company uses risk-free discount 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.
Income Taxes
Tax regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change
and there are differing interpretations requiring management judgment. Deferred tax assets are recognized when it is considered
probable that deductible temporary differences will be recovered in future periods, which requires management judgment. Deferred
tax liabilities are recognized when it is considered probable that temporary differences will be payable to tax authorities in future
periods, which requires management judgment. Income tax filings are subject to audit and re-assessment and changes in facts,
circumstances and interpretations of the standards may result in a material change to the Company's provision for income taxes.
SPECIFIED FINANCIAL MEASURES
In this MD&A, we refer to certain specified financial measures (such as free cash flow, operating netback, total sales, net of
blending and other expense, heavy oil sales, net of blending and other expense, and average royalty rate) which do not have any
standardized meaning prescribed by IFRS. While these measures 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. This MD&A also contains the terms "adjusted funds flow" and "net debt" which are capital management measures. We
believe that inclusion of these specified financial measures provides useful information to financial statement users when
evaluating the financial results of Baytex.
Non-GAAP Financial Measures
Total sales, net of blending and other expense and heavy oil, net of blending and other expense
Total sales, net of blending and other expense and heavy oil, net of blending and other expense represent the total revenues and
heavy oil revenues realized from produced volumes during a period, respectively. Total sales, net of blending and other expense is
comprised of total petroleum and natural gas sales adjusted for blending and other expense. Heavy oil, net of blending and other
expense is calculated as heavy oil sales less blending and other expense. We believe including the blending and other expense
associated with purchased volumes is useful when analyzing our realized pricing for produced volumes against benchmark
commodity prices.
The following table reconciles heavy oil, net of blending and other expense to amounts disclosed in the primary financial
statements in the following table.
($ thousands)
Petroleum and natural gas sales
Light oil and condensate (1)
NGL (1)
Natural gas sales (1)
Three Months Ended
Years Ended December 31
December 31,
2023
September 30,
2023
December 31,
2022
2023
2022
$
1,065,515 $
1,163,010 $
648,986 $
3,382,621 $
2,889,045
(675,072)
(756,779)
(330,016)
(2,029,123)
(1,470,549)
(57,027)
(43,674)
(46,972)
(35,987)
(27,276)
(48,116)
(145,997)
(125,952)
(120,505)
(195,915)
Heavy oil sales
Blending and other expense - heavy oil (2)
Heavy oil, net of blending and other expense
$
$
289,742 $
323,272 $
243,578 $
1,081,549 $
1,102,076
(62,296)
(49,830)
(50,174)
(224,802)
(189,454)
227,446 $
273,442 $
193,404 $
856,747 $
912,622
(1) Component of petroleum and natural gas sales; see Note 14 Petroleum and Natural Gas Sales in the Consolidated Financial Statements for the
year ended December 31, 2023 for further information.
(2) The portion of blending and other expense that relates to heavy oil sales for the applicable period.
Operating netback
Operating netback and operating netback after financial derivatives are used to assess our operating performance and our ability to
generate cash margin on a unit of production basis. Operating netback is comprised of petroleum and natural gas sales, less
blending expense, royalties, operating expense and transportation expense. Realized financial derivatives gains and losses are
added to operating netback to provide a more complete picture of our financial performance as our financial derivatives are used to
provide price certainty on a portion of our production.
44
2023 / Annual Report / Baytex Energy
The following table reconciles operating netback and operating netback after realized financial derivatives to petroleum and natural
gas sales.
($ thousands)
Petroleum and natural gas sales
Blending and other expense
Total sales, net of blending and other expense
Royalties
Operating expense
Transportation expense
Three Months Ended
Years Ended December 31
December 31,
2023
September 30,
2023
December 31,
2022
2023
2022
$
$
1,065,515 $
1,163,010 $
648,986 $
3,382,621 $
2,889,045
(62,296)
(49,830)
(50,174)
(224,802)
(189,454)
1,003,219 $
1,113,180 $
598,812 $
3,157,819 $
2,699,591
(228,570)
(164,873)
(29,744)
(240,049)
(174,119)
(27,983)
(121,691)
(104,335)
(14,817)
(669,792)
(570,839)
(89,306)
(562,964)
(422,666)
(48,561)
Operating netback
Realized financial derivatives gain (loss) (1)
$
580,032 $
671,029 $
357,969 $
1,827,882 $
1,665,400
12,377
2,055
(49,665)
36,212
(334,481)
Operating netback after realized financial derivatives $
592,409 $
673,084 $
308,304 $
1,864,094 $
1,330,919
(1) Realized financial derivatives gain or loss is a component of financial derivatives gain or loss; see Note 18 Financial Instruments and Risk
Management in the Consolidated Financial Statements for the year ended December 31, 2023 for further information.
Free cash flow
We use free cash flow to evaluate our financial performance and to assess the cash available for debt repayment, common share
repurchases, dividends and acquisition opportunities. Free cash flow is comprised of cash flows from operating activities adjusted
for changes in non-cash working capital, additions to exploration and evaluation assets, additions to oil and gas properties,
payments on lease obligations, transaction costs, and cash premiums on derivatives.
Free cash flow is reconciled to cash flows from operating activities in the following table.
($ thousands)
Three Months Ended
Years Ended December 31
December 31,
2023
September 30,
2023
December 31,
2022
2023
2022
Cash flow from operating activities
$
474,452 $
444,033 $
303,441 $
1,295,731 $
1,172,872
Change in non-cash working capital
Transaction costs
Additions to exploration and evaluation assets
14,971
5,079
1,271
126,075
(55,632)
220,895 $
(26,072)
2,263
(40)
—
(462)
49,045
—
—
(6,359)
Additions to oil and gas properties
(200,537)
(409,151)
(103,172)
(1,012,787)
(515,183)
Payments on lease obligations
Cash premiums on derivatives
Free cash flow
(4,451)
—
(4,740)
—
(851)
—
(11,527)
2,263
(3,732)
—
$
290,785 $
158,440 $
143,324 $
543,620 $
621,526
As a result of changes in commodity prices, development plans and capital costs, higher interest rates and debt outstanding, along
with the Viking disposition, we no longer expect to generate $1 billion of free cash flow for the period from July 1, 2023 to June 30,
2024, as stated in our press release dated June 20, 2023. We are no longer providing an estimate of our free cash flow for the
aforementioned period. Please see our press release dated February 28, 2024 available on SEDAR+ at www.sedarplus.com for
our current expectations regarding free cash flow for full year 2024.
Non-GAAP Financial Ratios
Heavy oil, net of blending and other expense per bbl
Heavy oil, net of blending and other expense per bbl represents the realized price for produced heavy oil volumes during a period.
Heavy oil, net of blending and other expense is a non-GAAP measure that is divided by barrels of heavy oil production volume for
the applicable period to calculate the ratio. We use heavy oil, net of blending and other expense per bbl to analyze our realized
heavy oil price for produced volumes against the WCS benchmark price.
2023 / Annual Report / Baytex Energy 45
Total sales, net of blending and other expense per boe
Total sales, net of blending and other per boe is used to compare our realized pricing to applicable benchmark prices and is
calculated as total sales, net of blending and other expense (a non-GAAP financial measure) divided by barrels of oil equivalent
production volume for the applicable period.
Average royalty rate
Average royalty rate is used to evaluate the performance of our operations from period to period and is comprised of royalties
divided by total sales, net of blending and other expense (a non-GAAP financial measure). 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.
Operating netback per boe
Operating netback per boe is operating netback (a non-GAAP financial measure) divided by barrels of oil equivalent production
volume for the applicable period and is used to assess our operating performance on a unit of production basis. Realized financial
derivative gains and losses per boe are added to operating netback per boe to arrive at operating netback after financial derivatives
per boe. Realized financial derivatives gains and losses are added to operating netback to provide a more complete picture of our
financial performance as our financial derivatives are used to provide price certainty on a portion of our production.
Capital Management Measures
Net debt
We use net debt to monitor our current financial position and to evaluate existing sources of liquidity. We also use net debt
projections to estimate future liquidity and whether additional sources of capital are required to fund ongoing operations. Net debt is
comprised of our credit facilities and long-term notes outstanding adjusted for unamortized debt issuance costs, trade payables,
share-based compensation liability, dividends payable, other long-term liabilities, cash, trade receivables, and prepaids and other
assets.
The following table summarizes our calculation of net debt.
($ thousands)
Credit Facilities
Unamortized debt issuance costs - Credit Facilities (1)
Long-term notes
Unamortized debt issuance costs - Long-term notes (1)
Trade payables
Share-based compensation liability
Dividends payable
Other long-term liabilities
Cash
Trade receivables
Prepaids and other assets
Net debt
As at
December 31,
2023
September 30,
2023
December 31,
2022
$
848,749 $
1,028,867 $
383,031
15,987
17,889
1,562,361
1,600,397
35,114
477,295
35,732
18,381
19,147
(55,815)
(339,405)
(83,259)
37,243
685,392
—
19,138
—
(23,899)
(540,679)
—
2,363
547,598
6,999
227,332
54,072
—
—
(5,464)
(222,108)
(6,377)
$
2,534,287 $
2,824,348 $
987,446
(1) Unamortized debt issuance costs were obtained from Note 8 Credit Facilities and Note 9 Long-term Notes from the Consolidated Financial
Statements for the year ended December 31, 2023. These amounts represent the remaining balance of costs that were paid by Baytex at the
inception of the contract.
Adjusted funds flow
Adjusted funds flow is used to monitor operating performance and the Company's ability to generate funds for exploration and
development expenditures and settlement of abandonment obligations. Adjusted funds flow is comprised of cash flows from
operating activities adjusted for changes in non-cash working capital, asset retirements obligations settled during the applicable
period, transaction costs and cash premiums on derivatives.
46
2023 / Annual Report / Baytex Energy
Adjusted funds flow is reconciled to amounts disclosed in the primary financial statements in the following table.
($ thousands)
Three Months Ended
Years Ended December 31
December 31,
2023
September 30,
2023
December 31,
2022
2023
2022
Cash flows from operating activities
$
474,452 $
444,033 $
303,441 $
1,295,731 $
1,172,872
Change in non-cash working capital
Asset retirement obligations settled
Transaction costs
Cash premiums on derivatives
14,971
7,646
5,079
—
126,075
9,252
2,263
—
(55,632)
7,743
—
—
220,895
26,416
49,045
2,263
(26,072)
18,351
—
—
Adjusted funds flow
$
502,148 $
581,623 $
255,552 $
1,594,350 $
1,165,151
CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
As of December 31, 2023, an evaluation was conducted to determine 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 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, 2023. As permitted by applicable
securities laws in Canada and the U.S., management excluded from its design and assessment the internal control over financial
reporting for Ranger Oil Corporation ("Ranger"), which was acquired on June 20, 2023. The consolidated financial statements as at
and for the year ended December 31, 2023 include $3.5 billion of total assets and $691.9 million of revenues, net of royalties from
the acquired entity.
The effectiveness of our internal control over financial reporting as of December 31, 2023 has been audited by KPMG LLP, an
independent registered public accounting firm, as stated in their Report of Independent Registered Public Accounting Firm.
2023 / Annual Report / Baytex Energy 47
Changes in Internal Control over Financial Reporting
Management excluded from its design and assessment the internal control over financial reporting for Ranger Oil Corporation
("Ranger") (as permitted by applicable securities laws in Canada and the U.S.), which was acquired on June 20, 2023. Other than
Ranger, there has been no change in the Baytex's internal control over financial reporting that occurred during the year ended
December 31, 2023 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial
reporting.
In accordance with the provision of NI 52-109 and consistent with the SEC guidance, the scope of the evaluation did not include
internal controls over financial reporting of Ranger. On June 20, 2023, Baytex completed the acquisition of Ranger, a publicly
traded oil and gas company that was listed on the NASDAQ exchange. Ranger's operations have been included in the
consolidated financial statements of Baytex since June 20, 2023. However, Baytex has not had sufficient time to appropriately
assess the disclosure controls and procedures and internal controls over financial reporting previously used by Ranger and
integrate them with those of Baytex. As a result, the certifying officers have limited the scope of their design of disclosure controls
and procedures and internal controls over financial reporting to exclude controls, policies and procedures of Ranger (as permitted
by applicable securities laws in Canada and the U.S.). Baytex has a program in place to complete its assessment of the controls,
policies and procedures of the acquired operations by June 20, 2024.
In 2023, the assets previously held by Ranger contributed revenues of $939.4 million (representing 28% of total revenues) and net
income before tax of $165.1 million. At December 31, 2023, current assets of $220.3 million, non-current assets of $3.3 billion,
current liabilities of $250.8 million and non-current liabilities of $97.7 million were associated with the acquired entity.
48
2023 / Annual Report / Baytex Energy
SELECTED ANNUAL INFORMATION
The following table summarizes key annual financial and operating information over the three most recently completed financial
years.
($ thousands, except per common share amounts)
Revenues, net of royalties
Adjusted funds flow (1)
Per common share - basic
Per common share - diluted
Net (loss) income
Per common share - basic
Per common share - diluted
Total assets
Credit facilities - principal
Long-term notes - principal
Total sales, net of blending and other expense ($/boe) (2)
Total production (boe/d)
$
$
$
$
$
$
$
$
$
$
$
2023
2022
2021
2,712,829 $
2,326,081 $
1,529,039
1,594,350 $
1,165,151 $
745,628
2.26 $
2.26 $
2.09 $
2.07 $
1.32
1.30
(233,356) $
855,605 $
1,613,600
(0.33) $
(0.33) $
1.53 $
1.52 $
2.86
2.82
7,460,931 $
5,103,769 $
4,834,643
864,736 $
1,597,475 $
70.82 $
122,154
385,394 $
554,597 $
88.56 $
83,519
506,514
885,920
60.93
80,156
(1) Capital management measure. Refer to the Specified Financial Measures section in this MD&A for further information.
(2) Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation
of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.
2023 / Annual Report / Baytex Energy 49
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: expectation that we can effectively
allocate capital across our assets; our intentions of allocating our annual free cash flow to shareholder returns through share
buybacks, dividends and debt reduction; that production growth will be driven by our Canadian assets; our commitment to reduce
our inactive wellbore count; for 2023, our capital budget, expected average daily production, expected royalty rate and operating
expense, transportation expense, general and administrative expense, cash interest expense, current income taxes, lease
expenditures and asset retirement obligations settled; the existence, operation and strategy of our risk management program; that
we intend to settle outstanding share based compensation awards in cash; the expected time to resolve the reassessment of our
tax filings by the Canada Revenue Agency; our objective to maintain a strong balance sheet to execute development programs,
deliver shareholder returns and optimize our portfolio through strategic acquisitions; that we may issue or repurchase debt or equity
securities from time to time or sell assets; our intent to fund certain financial obligations with cash flow from operations and the
expected timing of the financial obligations. 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. 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: oil and natural gas prices
and differentials between light, medium and heavy crude 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; that we will have sufficient financial resources in the future to provide shareholder returns; 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 risk of an extended period of low oil and natural gas
prices; risks associated with our ability to develop our properties and add reserves; that we may not achieve the expected benefits
of acquisitions and we may sell assets below their carrying value; the availability and cost of capital or borrowing; restrictions or
costs imposed by climate change initiatives and the physical risks of climate change; the impact of an energy transition on demand
for petroleum productions; availability and cost of gathering, processing and pipeline systems; retaining or replacing our leadership
and key personnel; changes in income tax or other laws or government incentive programs; risks associated with large projects;
risks associated with higher a higher concentration of activity and tighter drilling spacing; costs to develop and operate our
properties; current or future controls, legislation or regulations; restrictions on or access to water or other fluids; public perception
and its influence on the regulatory regime; new regulations on hydraulic fracturing; regulations regarding the disposal of fluids; risks
associated with our hedging activities; variations in interest rates and foreign exchange rates; uncertainties associated with
estimating oil and natural gas reserves; our inability to fully insure against all risks; risks associated with a third-party operating our
Eagle Ford properties; additional risks associated with our thermal heavy crude oil projects; our ability to compete with other
organizations in the oil and gas industry; risks associated with our use of information technology systems; adverse results of
litigation; that our Credit Facilities may not provide sufficient liquidity or may not be renewed; failure to comply with the covenants in
our debt agreements; risks associated with expansion into new activities; the impact of Indigenous claims; risks of counterparty
default; impact of geopolitical risk and conflicts; loss of foreign private issuer status; conflicts of interest between the Company and
its directors and officers; variability of share buybacks and dividends; 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, 2023, to be filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission
not later than March 31, 2024 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.
50
2023 / Annual Report / Baytex Energy
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.
Dividend Advisory
Baytex’s future shareholder distributions, including but not limited to the payment of dividends, if any, and the level thereof is uncertain. Any
decision to pay dividends on the common shares (including the actual amount, the declaration date, the record date and the payment date in
connection therewith) will be subject to the discretion of the Board of Directors of Baytex and may depend on a variety of factors, including, without
limitation, Baytex’s business performance, financial condition, financial requirements, growth plans, expected capital requirements and other
conditions existing at such future time including, without limitation, contractual restrictions and satisfaction of the solvency tests imposed on Baytex
under applicable corporate law. Further, the actual amount, the declaration date, the record date and the payment date of any dividend are subject
to the discretion of the Board of Directors of Baytex.
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.
Risks Relating to Our Business and Operations
Crude oil and natural gas prices are volatile. An extended period of low oil and natural gas prices could have a material
adverse effect on our business, results of operations, or cash flows and financial condition
Our financial condition is substantially dependent on, and highly sensitive to, the prevailing prices of crude oil and natural gas. Low
prices for crude oil and natural gas produced by us could have a material adverse effect on our operations, financial condition and
the value and amount of our reserves.
Prices for crude oil and natural gas fluctuate in response to changes in the supply of, and demand for, crude oil and natural gas,
market uncertainty and a variety of additional factors beyond our control. Crude oil prices are primarily determined by international
supply and demand. Factors which affect crude oil prices include the actions of OPEC, OPEC+, the condition of the Canadian,
United States, European and Asian economies, the impacts of geopolitical events, including the Russian Ukrainian war and
conflicts in the Middle East, or other adverse economic or political development in the United States, Europe, or Asia, the impact of
pandemics/epidemics, government regulation, 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. Additionally, the occurrence
or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. 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 crude oil and heavy crude 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.
There is also a risk that refining capacity in the U.S. Gulf Coast may be insufficient to refine all of the light sweet crude oil being
produced in the U.S. If light sweet crude oil production remains at current levels or continues to increase, demand for the light
crude oil production from our U.S. operations could result in widening price discounts to the world crude prices.
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
change, the carrying value of our assets could be subject to revision and our net earnings could be adversely affected.
Our success is highly dependent on our ability to develop existing properties and add to our oil and natural gas reserves
Our oil and natural gas reserves are a depleting resource and decline as such reserves are produced. As a result, our long-term
commercial success depends on our ability to find, acquire, develop and commercially produce oil and natural gas reserves. Future
oil and natural gas exploration may involve unprofitable efforts, not only from unsuccessful wells, but also from wells that are
2023 / Annual Report / Baytex Energy 51
productive but do not produce sufficient hydrocarbons to return a profit. Completion of a well does not assure a profit on the
investment. Drilling hazards or environmental liabilities or damages and various field operating conditions could greatly increase
the cost of operations and adversely affect the production from successful wells. Field operating conditions include, but are not
limited to, delays or failure in obtaining governmental, landowner or other stakeholder approvals or consents, shut-ins of connected
wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical
conditions. While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over
time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely
affect revenue and cash flow from operating activities to varying degrees.
There is no assurance we will be successful in developing our reserves or acquiring additional reserves at acceptable costs.
Without these reserves additions, our reserves will deplete and as a consequence production from and the average reserve life of
our properties will decline, which may adversely affect our business, financial condition, results of operations and prospects.
The anticipated benefits of acquisitions may not be achieved and the Company may dispose of non-core
assets for less than their carrying value on the financial statements
Acquisition of oil and gas properties is a key element of maintaining and growing reserves and production. Competition for these
assets has been and will continue to be intense. We may not be able to identify attractive acquisition opportunities. Even if we do
identify attractive candidates, we may not be able to complete the acquisition or do so on commercially acceptable terms.
Achieving the benefits of acquisitions depends on successfully consolidating functions and integrating operations and procedures
in a timely and efficient manner and the Company's ability to realize the anticipated growth opportunities and synergies from
combining the acquired businesses and operations with those of the Company. The integration of acquired businesses and assets
may require substantial management effort, time and resources diverting management's focus from other strategic opportunities
and operational matters. Additionally, significant acquisitions can change the nature of our operations and business if acquired
properties have substantially different operating and geological characteristics or are in different geographic locations than our
existing properties. To the extent that acquired properties are substantially different than our existing properties, our ability to
efficiently realize the expected economic benefits of such transactions may be limited.
Management continually assesses the value and contribution of our assets. In this regard, non-core assets may be periodically
disposed of so that the Company can focus its efforts and resources more efficiently. Depending on the state of the market for such
non-core assets, certain non-core assets of the Company, if disposed of, may realize less on disposition than their carrying value
on the financial statements of the Company.
Availability and cost of capital or borrowing to maintain and/or fund future development and acquisitions
The business of exploring for, developing or acquiring reserves is capital intensive. If external sources of capital (including, but not
limited to, debt and equity financing) 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. Unpredictable financial
markets and the associated credit impacts may impede our ability to secure and maintain cost effective financing and limit our
ability to achieve timely access to capital on acceptable terms and conditions. If external sources of capital become limited or
unavailable, our ability to make capital investments, continue our business plan, meet all of our financial obligations as they come
due and maintain existing properties may be impaired.
Our ability to obtain additional capital is dependent on, among other things, a general interest in energy industry investments and,
in particular, interest in our securities along with our ability to maintain our credit ratings. If we are unable to maintain our
indebtedness and financial ratios at levels acceptable to our credit rating agencies, or should our business prospects deteriorate,
our credit ratings could be downgraded. Additionally, from time to time, our securities may not meet the investment criteria or
characteristics of a particular institutional or other investor, including institutional investors who are not willing or able to hold
securities of oil and gas companies for reasons unrelated to financial or operational performance. This may include changes to
market-based factors or investor strategies, including ESG, or responsible investing criteria/rankings (for example, ESG, social
impact or environmental scores), the implementation of new financial market regulations and fossil fuel divestment initiatives
undertaken by governments, pension funds and/or other institutional investors. These events would adversely affect the value of
our outstanding securities and existing debt and our ability to obtain new financing, and may increase our borrowing costs.
From time to time we may enter into transactions which may be financed in whole or in part with debt or equity. The level of our
indebtedness from time to time, could impair our ability to obtain additional financing on a timely basis to take advantage of
business opportunities that may arise. Additionally, from time to time, we may issue securities from treasury in order to reduce debt,
complete acquisitions and/or optimize our capital structure.
52
2023 / Annual Report / Baytex Energy
Restrictions and/or costs associated with regulatory initiatives to combat climate change and the physical risks of climate
change may have a material adverse affect on our business
Regulatory and Policy Initiatives
Our exploration and production facilities and other operational activities emit GHGs. As such, GHG emissions regulation (including
carbon taxes) enacted in jurisdictions where we operate will impact us. In addition, certain of our assets have a higher GHG
emissions intensity than others and may be disproportionately impacted.
Negative consequences which could result from new GHG emissions regulation include, but are not limited to: increased operating
costs, additional taxes, 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 financial condition, results of operations or prospects.
Although we provide for the necessary amounts in our annual capital budget to fund our currently estimated obligations, there can
be no assurance that we will be able to satisfy our actual future obligations associated with GHG emissions from such funds.
Physical Risk
Climate change has been linked to extreme weather conditions. Extreme hot and cold weather, heavy snowfall, heavy rain fall,
hurricanes, drought and wildfires may restrict our ability to access our properties, cause operational difficulties including damage to
machinery and facilities. Extreme weather also increases the risk of personnel injury as a result of dangerous working conditions.
Certain assets are located where they are exposed to forest fires, floods, heavy rains, hurricanes, drought and other extreme
weather conditions which can lead to significant downtime, damage to such assets and/or increased costs of construction and
maintenance. Moreover, extreme weather conditions may lead to disruptions in our ability to transport produced oil and natural gas
as well as goods and services in our supply chain.
An energy transition that lessens demand for petroleum products may have an adverse affect on our business
A transition away from the use of petroleum products, which may include 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.
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 to 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. In addition, many of the pipeline systems that we use are controlled by a single company and rates are set through a
regulatory process, as a result we are subject to the outcome of those regulatory processes. Any significant change in market
factors, regulatory decisions 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.
Our operations in the United States are concentrated in the Eagle Ford shale of South Texas and as a result are highly exposed to
the gulf coast refining complex and events which negatively impact the functioning of infrastructure in that area which could harm
our business and, in turn, our financial condition. Such events include adverse weather conditions, terrorism, local market changes,
government regulation and taxation which may result in limitations on the U.S.' ability to export crude oil.
Access to the pipeline capacity for the export of crude oil from Canada has, at times, been inadequate for the amount of Canadian
production being exported. This has resulted in significantly lower prices being realized by Canadian producers compared with the
WTI price and the Brent price for crude oil. In addition, the pro-rationing of capacity on inter-provincial pipeline systems continues
to affect the ability to export oil and natural gas from Canada. There can be no certainty that current investment in pipelines will
provide sufficient long-term take-away capacity or that currently operating systems will remain in service. There is also no certainty
that short-term operational constraints on pipeline systems, arising from pipeline interruption and/or increased supply of crude oil,
will not occur.
2023 / Annual Report / Baytex Energy 53
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 retain or replace our leadership and key personnel may have an adverse affect on our business
Our success is dependent upon our management, our leadership capabilities and the quality and competency of our talent.
Contributions of the existing management team to the immediate and near-term operations of the Company are likely to be of
central importance. In addition, certain of the Company's current employees may have significant institutional knowledge that must
be transferred to other employees prior to their departure from the workforce. If we are unable to retain key personnel and critical
talent or to attract and retain new talent with the necessary leadership, professional and technical competencies, it could have a
material adverse effect on our financial condition, results of operations and prospects.
Income tax laws or other laws or government incentive programs or regulations relating to our industry may in the future
be changed or interpreted in a manner that adversely affects us and our Shareholders
Income tax laws and government incentive programs relating to the oil and gas industry may change in a manner that adversely
affects our financial condition, results of operations and prospects.
In addition, 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. 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. At present, the Canadian tax authorities have
reassessed the returns of certain of our subsidiaries. Any such reassessment may have an impact on current and future taxes
payable. We believe appropriate provisions for current and deferred income taxes have been made in our Financial Statements;
however, it is difficult to predict the outcome of audit findings by tax authorities. These findings may increase the amount of our tax
liabilities and adversely affect our business, financial condition and results of operations.
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, community relationships 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.
We could experience adverse impacts associated with a high concentration of activity and tighter drilling spacing
We are subject to drilling, completion and operating risks, including our ability to efficiently execute large-scale project
development, as we could experience delays, curtailments and other adverse impacts associated with a high concentration of
activity and tighter drilling spacing. A higher concentration of activity and tighter drilling spacing may increase the frequency of
operational shut-ins and unintentional communication with other adjacent wells and reduce the total recoverable reserves from the
reservoir.
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, access to
skilled and unskilled labour, availability of equipment, scheduling delays, trucking and fuel costs, failure to maintain quality
construction standards, the cost of new technologies and supply chain disruptions. Labour costs, natural gas, electricity, water,
diluent and chemicals are examples of some of the operating and other costs that are susceptible to significant fluctuation.
Increases to development and operating costs could have a material adverse effect on our financial condition, results of operations
or prospects.
54
2023 / Annual Report / Baytex Energy
Current or future controls, legislation or regulations applicable to the oil and gas industry could adversely affect us
Operations
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.
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. 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 our financial condition,
results of operations or prospects.
Environment
All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation
pursuant to a variety of federal, state, provincial and local laws and regulations. Environmental legislation provides for, among other
things, the initiation and approval of new oil and natural gas projects, and restrictions and prohibitions on the spill, release or
emission of various substances produced in association with oil and natural gas industry operations. In addition, such legislation
sets out the requirements with respect to oilfield waste handling and storage, habitat protection and the satisfactory operation,
maintenance, abandonment and reclamation of well and facility sites. New environmental legislation at the federal, state, and
provincial levels may increase uncertainty among oil and natural gas industry participants as the new laws are implemented, and
the effects of the new rules and standards are felt in the oil and natural gas industry.
Compliance with environmental legislation can require significant expenditures and a breach of applicable environmental legislation
may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a
manner expected to result in stricter standards and enforcement, larger fines and liabilities and potentially increased capital
expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to
liabilities to governments and third parties and may require the Company to incur costs to remedy such discharge. Although the
Company believes that it is in material compliance with current applicable environmental legislation, no assurance can be given
that environmental compliance requirements will not result in a curtailment of production or a material increase in the costs of
production, development or exploration activities or otherwise have a material adverse effect on our business, financial condition,
results of operations and prospects.
The Company may have to pay certain costs associated with abandonment and reclamation
The Company will need to comply with the terms and conditions of environmental and regulatory approvals and all legislation
regarding the abandonment of its projects and reclamation of the project lands at the end of their economic life, which may result in
substantial abandonment and reclamation costs. Any failure to comply with the terms and conditions of the Company's approvals
and legislation may result in the imposition of fines and penalties, which may be material. Generally, abandonment and reclamation
costs are substantial. The Company records a provision for abandonment and reclamation costs in its financial statements, this
provision requires significant judgement and reflects the Company's best estimate of the costs to complete the required
abandonment and reclamation work. Actual results may be significantly different than the estimated amounts.
Foreign Investment and Competition Act Legislation
In addition to regulatory requirements mentioned above, our business and financial condition could be influenced by federal
legislation affecting, in particular, foreign investment, through legislation such as the Competition Act (Canada) and the Investment
Canada Act (Canada) and the Hart-Scott-Rodino Antitrust Improvements Act in the United States.
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, SAGD, CSS 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, SAGD, CSS and waterflooding. If the Company is unable to access such water
it may not be able to undertake hydraulic fracturing, SAGD, CSS or waterflooding activities, which may reduce the amount of oil
and natural gas that the Company is ultimately able to produce from its reserves.
2023 / Annual Report / Baytex Energy 55
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.
New regulations on hydraulic fracturing may lead to operational delays, increased costs and/or decreased production
volumes
Hydraulic fracturing involves the injection of water, sand and small amounts of additives under pressure into rock formations to
stimulate the production of oil and natural gas. Specifically, hydraulic fracturing enables the production of commercial quantities of
oil and natural gas from reservoirs that were previously unproductive. Hydraulic fracturing has featured prominently in recent
political, media and activist commentary on the subject of water usage, induced seismicity events and environmental damage. Any
new laws, regulations or permitting requirements regarding hydraulic fracturing could lead to operational delays, increased
operating costs, third party or governmental claims, and could increase the 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.
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, provincial and state governments, including its effect on fresh water supplies
and the ability of such water to be recycled, amongst other things. While it is difficult to predict the impact of any regulations that
may be enacted in response to such review, the implementation of stricter regulations may increase the Company's costs of
compliance.
Our economic 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 derivative 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 for certain assets will result in us paying royalties at a reference price which is higher than the hedged price. We may also
suffer financial loss due to derivative 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 derivative 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 economic hedges at prices that have an equivalent benefit to us, which may
adversely impact our revenues in future periods.
Variations in interest rates and foreign exchange rates could adversely affect our financial condition
There is a risk that interest rates will continue to increase. An increase in interest rates could result in a significant increase in the
amount we pay to service debt and could have an adverse effect on our financial condition, results of operations and prospects.
World oil prices are quoted in United States dollars and the price received by Canadian producers is therefore affected by the
Canada/U.S. foreign exchange rate that may fluctuate over time. A material increase in the value of the Canadian dollar may
negatively impact our revenues. A substantial portion of our operations and production are in the United States and, as such, we
are exposed to foreign currency risk on both revenues and costs to the extent the value of the Canadian dollar decreases relative
to the U.S. dollar. In addition, we are exposed to foreign currency risk as a large portion of our indebtedness is denominated in
U.S. dollars and the interest payable thereon is payable in U.S. dollars. Future Canada/U.S. foreign exchange rates could also
impact the future value of our reserves as determined by our independent evaluator.
A decline in the value of the Canadian dollar relative to the United States dollar provides a competitive advantage to United States
companies acquiring Canadian oil and gas properties and may make it more difficult for us to replace reserves through
acquisitions.
56
2023 / Annual Report / Baytex Energy
There are numerous uncertainties inherent in estimating quantities of recoverable oil and natural gas reserves, including
many factors beyond our control
The reserves estimates are estimates only. 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, 2023 are estimated using forecast prices and costs. If we realize lower prices for crude oil, natural
gas liquids and natural gas and they are substituted for the estimated price assumptions, the present value of estimated future net
revenues for our reserves and net asset value would be reduced and the reduction could be significant. Our actual production,
revenues, royalties, taxes and development, abandonment and operating expenditures with respect to our reserves will likely vary
from such estimates, and such variances could be material.
Estimates of reserves that may be developed and produced in the future are often based upon volumetric calculations and upon
analogy to similar types of reserves, rather than upon actual production history. Subsequent evaluation of the same reserves based
upon production history will result in variations in the previously estimated reserves and such variances could be material.
Acquiring, developing and exploring for oil and natural gas involves many physical hazards. We have not insured and
cannot fully insure against all risks related to our operations
Our crude oil and natural gas operations are subject to all of the risks normally incidental to the: (i) storing, transporting,
processing, refining and marketing of crude oil, natural gas and other related products; (ii) drilling and completion of crude oil and
natural gas wells; and (iii) operation and development of crude oil and natural gas properties, including, but not limited to:
encountering unexpected formations or pressures, premature declines of reservoir pressure or productivity, blowouts, fires,
explosions, equipment failures and other accidents, gaseous leaks, uncontrollable or unauthorized flows of crude oil, natural gas or
well fluids, migration of harmful substances, oil spills, corrosion, adverse weather conditions, pollution, acts of vandalism, theft and
terrorism and other adverse risks to the environment.
Although we maintain insurance in accordance with customary industry practice, we are not fully insured against all of these risks
nor are all such risks insurable and in certain circumstances we may elect not to obtain insurance to deal with specific risks due to
the high premiums associated with such insurance or other reasons. In addition, the nature of these risks is such that liabilities
could exceed policy limits, in which event we could incur significant costs that could have a material adverse effect on our
business, financial condition, results of operations and prospects.
We are not the operator of a significant portion of our drilling locations in the Eagle Ford and, therefore, we will not be
able to control the timing of development, associated costs or the rate of production of that acreage
Marathon Oil is the operator of a significant portion of our Eagle Ford acreage which is located in the Karnes and Atascosa
counties and we are reliant upon Marathon Oil to operate successfully. Marathon Oil will make decisions based on its own best
interest and the collective best interest of all of the working interest owners of this acreage, which may not be in our best interest.
We have a limited ability to exercise influence over the operational decisions of Marathon Oil, including the setting of capital
expenditure budgets and determination of drilling locations and schedules. The success and timing of development activities,
operated by Marathon Oil, will depend on a number of factors that will largely be outside of our control, including the timing and
amount of capital expenditures, Marathon Oil's expertise and financial resources, approval of other participants in drilling wells,
selection of technology, and the rate of production of reserves.
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 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
2023 / Annual Report / Baytex Energy 57
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: the costs imposed by GHG emissions regulations, 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.
We may be unable to compete successfully with other organizations in the oil and natural gas industry, or obtain required
vendor services to compete.
The oil and natural gas industry is highly competitive in all of its phases. The Company competes with numerous other entities in
the exploration for, and the development, production and marketing of, oil and natural gas, as well as for capital, acquisitions of
reserves and/or resources, undeveloped lands, skilled/qualified labour, access to drilling rigs, service rigs and other equipment and
materials such as drilling rigs, hydraulic fracturing pumping equipment and related skilled personnel, access to processing facilities,
pipeline and refining capacity, as well as many other services, and in many other respects, with a substantial number of other
organizations, many of which may have greater technical and financial resources than the Company. As a result, some of the
Company's competitors may have greater opportunities and be able to access, services or vendors that the Company is not able to
access, thereby limiting its ability to compete.
Our information technology systems are subject to certain risks
We utilize and have become increasingly dependent upon a number of information technology systems for the administration and
management of our business and are subject to a variety of information technology and system risks as a part of our normal course
operations, including potential breakdown, invasion, virus, cyber-attack, cyber-fraud, security breach, and destruction or
interruption of the Company's information technology systems by third parties or insiders. 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 the Company has security measures and controls in place to mitigate these risks, a breach of its security
measures and/or a loss of information could occur and result in a loss of material and confidential information and reputation,
breach of privacy laws, and/or disruption to business activities. The significance of any such event is difficult to quantify but may in
certain circumstances be material and could have a material adverse effect on the Company's business, financial condition and
results of operations.
Adverse results from litigation may have an adverse affect on our business and reputation
In the normal course of our operations, we may become involved in, be named as a party to, or be the subject of, various legal
proceedings, including regulatory proceedings, tax proceedings and legal actions. Potential litigation may develop in relation to
personal injuries, including resulting from exposure to hazardous substances, property damage, property taxes, land and access
rights, environmental issues, including claims relating to contamination or natural resource damages and contract disputes. The
outcome with respect to outstanding, pending or future proceedings cannot be predicted with certainty and may be determined
adversely to us and could have a material adverse effect on our assets, liabilities, business, financial condition and results of
operations. Even if we prevail in any such legal proceedings, the proceedings could be costly and time-consuming and may divert
the attention of management and key personnel from business operations, which could have an adverse effect on our financial
condition.
Our Credit Facilities may not provide sufficient liquidity and a failure to renew our Credit Facilities at maturity could
adversely affect our financial condition
Our Credit Facilities and any replacement credit facilities may not provide sufficient liquidity. The amounts available under our
Credit Facilities may not be sufficient for future operations, or we may not be able to obtain additional financing on economic terms,
if at all. There can be no assurance that the amount of our Credit Facilities will be adequate for our future financial obligations,
including future capital expenditures, or that we will be able to obtain additional funds. In the event we are unable to refinance our
debt obligations, it may impact our ability to fund ongoing operations. In the event that the Credit Facilities are not extended prior
to maturity, indebtedness under the Credit Facilities will be repayable at that time. There is also a risk that the Credit Facilities will
not be renewed for the same amount or on the same terms.
Failure to comply with the covenants in the agreements governing our debt, including our obligation to repay the Senior
Notes at maturity, could adversely affect our financial condition
We are required to comply with the covenants in our Credit Facilities and the Senior Notes. If we fail to comply with such
covenants, are unable to repay or refinance amounts owned at maturity or pay the debt service charges or otherwise commit an
event of default, such as bankruptcy, it could result in the seizure and/or sale of our assets by our creditors. The proceeds from
58
2023 / Annual Report / Baytex Energy
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.
Expansion into New Activities
Our operations and the expertise of our management are currently focused primarily on oil and natural gas production, exploration
and development in the Provinces of Alberta and Saskatchewan and the State of Texas. In the future, we may acquire or move into
new industry related activities or new geographical areas and may acquire different energy-related assets. As a result, we may face
unexpected risks or, alternatively, our exposure to one or more existing risk factors may be significantly increased, which may in
turn result in our future operational and financial conditions being adversely affected.
Indigenous Land and Rights Claims
Opposition by Indigenous groups to the conduct of the Company's operations, development or exploratory activities in any of the
jurisdictions in which the Company conducts business may negatively impact it in terms of public perception, diversion of
management's time and resources, and legal and other advisory expenses, and could adversely impact the Company's progress
and ability to explore and develop properties.
Indigenous peoples have claimed Indigenous rights and title in portions of Western Canada. We are not aware that any claims
have been made in respect of our properties and assets. However, if a claim arose and was successful, such claim may have a
material adverse effect on our business, financial condition, results of operations and prospects. In addition, the process of
addressing such claims, regardless of the outcome, is expensive and time consuming and could result in delays in the construction
of infrastructure systems and facilities which could have a material adverse effect on our business and financial results.
We are subject to risk of default by the counterparties to our contracts and our counterparties may deem us to be a
default risk
We are subject to the risk that counterparties to our risk management contracts, marketing arrangements and operating
agreements and other suppliers of products and services may default on their obligations under such agreements or arrangements,
including as a result of liquidity requirements or insolvency. Furthermore, low oil and natural gas prices increase the risk of bad
debts related to our joint venture and industry partners. A failure by such counterparties to make payments or perform their
operational or other obligations to us may adversely affect our results of operations, cash flow from operating activities and
financial position. Conversely, our counterparties may deem us to be at risk of defaulting on our contractual obligations. These
counterparties may require that we provide additional credit assurances by prepaying anticipated expenses or posting letters of
credit, which would decrease our available liquidity and increase our costs.
Geopolitical risk and conflicts in or around major oil and gas producing nations can significantly impact commodity
prices and, therefore the financial condition of the oil and gas industry
Existing or future conflicts in major oil and gas producing nations and the international response may have potential wide-ranging
consequences for global market volatility and economic conditions, including affecting crude oil and natural gas prices. Financial
and trade sanctions that may be imposed against countries involved in such conflicts may have continued far-reaching effects on
the global economy, energy and commodity prices. The short-, medium- and long-term implications of any such conflicts is difficult
to predict with any degree of certainty. Depending on the extent, duration, and severity of such conflict(s), it may have the effect of
heightening many of the other risks described herein, including, without limitation, risks relating to global market volatility and
economic conditions; cybersecurity threats; crude oil and natural gas prices; inflationary pressures, interest rates and costs of
capital; and supply chains and cost-effective and timely transportation.
The Company could lose its status as a "foreign private issuer" in the United States
The Company is required to assess its "foreign private issuer" ("FPI") status under U.S. securities laws on an annual basis at the
end of its second quarter. While the Company currently qualifies as an FPI, it could lose its FPI status in the future. If the Company
were to lose its status as an FPI it would be required to fully comply with both U.S. and Canadian securities and accounting
requirements applicable to domestic issuers in each country. In addition, if the Company loses its FPI status, it would be required to
report as a U.S. domestic issuer and be subject to other U.S. securities laws applicable to U.S. domestic issuers. The regulatory
and compliance costs to our business under U.S. securities laws as a U.S. domestic issuer may be significantly greater than the
costs our business incurs as a foreign private issuer. For example, as a U.S. domestic issuer, the Company would be required to
file periodic reports and registration statements with the SEC on U.S. domestic issuer forms, which are more detailed and
extensive in certain respects than the forms available to the Company as a foreign private issuer. The Company would also be
required to report its oil and gas reserves and production information in accordance with applicable U.S. disclosure requirements.
Such conversion and modifications would involve additional costs and may restrict the Company’s access to capital markets for a
period of time until it has satisfied SEC reporting requirements. In addition, the Company may lose its ability to rely upon
exemptions from certain corporate governance requirements on U.S. stock exchanges that are available to FPIs, which could also
increase its costs.
2023 / Annual Report / Baytex Energy 59
Conflicts of interest may arise between the Company and its directors and officers
Circumstances may arise where directors and officers of the Company are directors or officers of other companies involved in the
oil and gas industry which are in competition to, or otherwise in conflict with, the interests of the Company. Directors are required to
abstain from voting on matters when they are in conflict. Employees, including officers, are not permitted to partake in activities that
do not support the best interests of the Company. Where employee conflicts exist, they are to be provided in writing to our Human
Resources Department, which discloses all conflicts to Chief Legal Officer. See the Company’s Code of Business Conduct and
Ethics at www.baytexenergy.com.
Risks Related to Ownership of our Securities
Changes in market-based factors may adversely affect the trading price of the Common Shares
The market price of our Common Shares is sensitive to a variety of market-based factors including, but not limited to, commodity
prices, interest rates, foreign exchange rates, the decision of certain indices to include our Common Shares and the comparability
of the Common Shares to other securities. Any changes in these market-based factors may adversely affect the trading price of the
Common Shares.
Forward-Looking Information rely upon assumptions which may not prove correct
Shareholders and prospective investors are cautioned not to place undue reliance on our forward-looking information. By its nature,
forward-looking information involves numerous assumptions, known and unknown risks and uncertainties, of both a general and
specific nature, that could cause actual results to differ materially from those suggested by the forward-looking information or
contribute to the possibility that predictions, forecasts or projections will prove to be materially inaccurate.
Dividends on the Company's Common Shares and Common Share repurchases are variable
The future acquisition by the Company of Common Shares pursuant to a share buyback (including through its NCIB) and the
payment of dividends, if any, and the level thereof is uncertain. Any decision to acquire Common Shares pursuant to a share
buyback or to pay dividends will be subject to the discretion of the Board and may depend on a variety of factors, including, without
limitation, our business performance, financial condition, financial requirements, commodity prices, growth plans, expected capital
requirements and other conditions existing at such future time including, without limitation, contractual restrictions and satisfaction
of the solvency tests imposed on the Company under applicable corporate law. In the future, there can be no assurance of the
number of Common Shares that the Company will acquire pursuant to a share buyback and there can be no assurance that
dividends will be paid or, if paid the amount of such dividends.
Certain Risks for United States and other non-resident Shareholders
The ability of investors resident in the United States to enforce civil remedies is limited
We are a corporation incorporated under the laws of the Province of Alberta, Canada, our principal office is located in Calgary,
Alberta and a substantial portion of our assets are located outside the United States. Most of our directors and officers and the
representatives of the experts who provide services to us (such as our auditors and our independent qualified reserves evaluators),
and all or a substantial portion of their assets are located outside the United States. As a result, it may be difficult for investors in
the United States to effect service of process within the United States upon such directors, officers and representatives of experts
who are not residents of the United States or to enforce against them judgments of the United States courts based upon civil
liability under the United States federal securities laws or the securities laws of any state within the United States. There is doubt as
to the enforceability in Canada against us or any of our directors, officers or representatives of experts who are not residents of the
United States, in original actions or in actions for enforcement of judgments of United States courts of liabilities based solely upon
the United States federal securities laws or securities laws of any state within the United States.
Canadian and United States practices differ in reporting reserves and production and our estimates may not be
comparable to those of companies in the United States
We report our production and reserves quantities in accordance with Canadian practices and specifically in accordance with NI
51-101. These practices are different from the practices used to report production and to estimate reserves in reports and other
materials filed with the SEC by companies in the United States.
We incorporate additional information with respect to production and reserves which is either not required to be included or
prohibited under rules of the SEC and practices in the United States. We follow the Canadian practice of reporting gross production
and reserve volumes (before deduction of Crown and other royalties). We also follow the Canadian practice of using forecast prices
and costs when we estimate our reserves, whereas the SEC rules require that a 12-month average price, calculated as the
unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the
reporting period, be utilized.
60
2023 / Annual Report / Baytex Energy
We have included estimates of proved reserves and proved and probable reserves. Probable reserves have a lower certainty of
recovery than proved reserves. The SEC requires oil and gas issuers in their filings with the SEC to disclose only proved reserves
but permits the optional disclosure of probable reserves. The SEC definitions of proved reserves and probable reserves are
different than NI 51-101; therefore, proved, probable and proved and probable reserves disclosed may not be comparable to
United States standards.
As a consequence of the foregoing, our reserves estimates and production volumes may not be comparable to those made by
companies utilizing United States reporting and disclosure standards.
There is additional taxation applicable to non-residents
Tax legislation in Canada may impose withholding or other taxes on the cash dividends, stock dividends or other property
transferred by us to non-resident shareholders. These taxes may be reduced pursuant to tax treaties between Canada and the
non-resident shareholder's jurisdiction of residence. Evidence of eligibility for a reduced withholding rate must be filed by the non-
resident shareholder in prescribed form with their broker (or in the case of registered shareholders, with the transfer agent). In
addition, the country in which the non-resident shareholder is resident may impose additional taxes on such dividends. Any of these
taxes may change from time to time.
2023 / Annual Report / Baytex Energy 61
MANAGEMENT'S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of Baytex Energy Corp. (the "Company") is responsible for establishing and maintaining adequate internal
control over financial reporting. Under the supervision of our President and Chief Executive Officer and our 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, 2023, our internal control over financial
reporting was effective. As permitted by applicable securities laws in Canada and the U.S., management excluded from its
design and assessment the internal control over financial reporting for Ranger Oil Corporation ("Ranger"), which was acquired on
June 20, 2023. The consolidated financial statements as at and for the year ended December 31, 2023 include $3.5 billion of
total assets and $691.9 million of revenues, net of royalties from the acquired entity.
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, 2023 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, 2023.
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.
/s/ Eric T. Greager
Eric T. Greager
President and Chief Executive Officer
Baytex Energy Corp.
February 28, 2024
/s/ Chad L. Kalmakoff
Chad L. Kalmakoff
Chief Financial Officer
Baytex Energy Corp.
62
2023 / Annual Report / Baytex Energy
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. (and subsidiaries) (the
“Company”) as of December 31, 2023 and 2022, the related consolidated statements of income (loss) and comprehensive
income (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, 2023 and 2022, and its financial performance and its cash flows for the years then
ended, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards
Board.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the Company’s internal control over financial reporting as of December 31, 2023, based on criteria established in
Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission, and our report dated February 28, 2024 expressed an unqualified opinion on the effectiveness of the Company’s
internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the
PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and
the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement,
whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the
consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such
procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial
statements. Our audits also included evaluating the accounting principles used and significant estimates made by management,
as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a
reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial
statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or
disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or
complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated
financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate
opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Assessment of the recoverable amount of oil and gas properties
As discussed in note 7 to the consolidated financial statements, the Company identified indicators of impairment as of December
31, 2023 related to the Company’s Viking and Eagle Ford Non-op cash generating units (CGUs). The Company therefore
determined the recoverable amount as of December 31, 2023 of each of the CGUs and recorded an impairment of $833.7
million. The determination of recoverable amount of a CGU involves numerous estimates, including cash flows associated with
estimated proved and probable oil and gas reserves of the CGU (“CGU reserves cash flows”) and the discount rate. The
estimation of CGU reserves cash flows in the reserve report involves the expertise of independent qualified reserve evaluators,
who take into consideration assumptions related to forecasted production volumes, royalty obligations, operating and capital
costs and commodity prices (collectively “CGU reserve report assumptions”). The Company engages independent qualified
reserve evaluators to estimate CGU reserves cash flows.
We identified the assessment of the recoverable amount of the Viking and Eagle Ford Non-op CGUs as a critical audit matter.
Changes in CGU reserve report assumptions and discount rates could have had a significant impact on the estimate of
recoverable amounts and the resulting impairment in the carrying amount of oil and gas properties relating to the CGUs. A high
degree of auditor judgment was required to evaluate the Company’s estimates of CGU reserves cash flows, and related CGU
reserve report assumptions, and the discount rates, which were inputs into the calculation of recoverable amounts. Additionally,
the evaluation of these recoverable amounts required involvement of valuation professionals with specialized skills and
knowledge.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested
the operating effectiveness of certain internal controls related to the critical audit matter. This included controls related to:
•
the Company’s determination of the recoverable amount of each of the CGUs, including the discount rate
2023 / Annual Report / Baytex Energy 63
•
the Company’s determination of the CGU reserve report assumptions and resulting CGU reserves cash flows.
We evaluated the competence, capabilities and objectivity of the independent qualified reserve evaluators engaged by the
Company, who estimated the CGU reserves cash flows. We evaluated the methodology used by the independent qualified
reserves evaluators to estimate the CGU reserves cash flows for compliance with the applicable regulatory standards. We
compared the current year actual CGU production volumes, royalty obligations, operating and capital costs to those estimates
used in the prior year estimate of proved reserves by CGU to assess the Company’s ability to accurately forecast. We assessed
the forecasted commodity prices used in the estimate of the CGU reserves cash flows by comparing them to those published by
other reserve engineering companies. We assessed the forecasted production volumes, royalty obligations, operating and capital
costs assumptions used in the current year estimate of the CGU reserves cash flows by comparing them to historical results. We
involved valuation professionals with specialized skills and knowledge, who assisted in:
•
•
evaluating the Company’s determination of discount rates by comparing the inputs of the discount rates against publicly
available market data for comparable assets and assessing the resulting discount rates
evaluating the Company’s estimate of recoverable amount of the CGUs by comparing to publicly available market data
and valuation metrics for comparable entities.
Fair value measurement of oil and gas properties in a business combination
As discussed in note 4 to the consolidated financial statements, the Company acquired Ranger Oil Corporation (“Ranger”) in a
business combination that was completed on June 20, 2023 (the “acquisition-date”). As a result of the transaction, the Company
acquired oil and gas properties with an acquisition-date fair value of $3,096.4 million, a portion of which related to oil and gas
properties with proved and probable oil and gas reserves. The determination of the acquisition-date fair value of the oil and gas
properties with proved and probable oil and gas reserves involves numerous estimates, including cash flows associated with
estimated acquired proved and probable oil and gas reserves (“acquired reserves cash flows”) and the discount rate. The
estimation of acquired reserves cash flows in the acquired reserve report involves the expertise of the independent qualified
reserve evaluators, who take into consideration assumptions related to forecasted production volumes, royalty obligations,
operating and capital costs and commodity prices (collectively “acquired reserve report assumptions”). The Company engages
independent qualified reserve evaluators to estimate the acquired reserves cash flows.
We identified the determination of the acquisition-date fair value of the oil and gas properties acquired in the Ranger business
combination as a critical audit matter. Changes in acquired reserve report assumptions and the discount rate could have had a
significant impact on the determination of the acquisition-date fair value of the acquired oil and gas properties. A high degree of
auditor judgment was required to evaluate the acquired reserve report assumptions and the discount rate, which were inputs into
the determination of the acquisition-date fair value. Additionally, the evaluation of this fair value required involvement of valuation
professionals with specialized skills and knowledge.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested
the operating effectiveness of certain internal controls related to this critical audit matter. This included controls related to:
•
•
the Company’s determination of the fair value, including the discount rate
the Company’s determination of the acquired reserve report assumptions and resulting acquired reserves cash flows.
We evaluated the competence, capabilities and objectivity of the independent qualified reserve evaluators engaged by the
Company, who estimated the acquired reserves cash flows. We evaluated the methodology used by the independent qualified
reserve evaluators to estimate the acquired reserves cash flows for compliance with the applicable regulatory standards. We
assessed the forecasted commodity prices used in the acquired reserve report by comparing them to those published by other
reserve engineering companies. We assessed the forecasted production volumes, royalty obligations, operating and capital
costs assumptions used in the acquired reserve report by comparing them to 2023 historical results for the Ranger oil and gas
properties post-acquisition and the Ranger reserve report assumptions.
We involved valuation professionals with specialized skills and knowledge, who assisted in:
•
•
evaluating the Company’s determination of the discount rate by comparing the inputs of the discount rate against
publicly available market data for comparable assets and assessed the resulting discount rate
evaluating the Company’s estimate of the acquisition-date fair value of the acquired oil and gas properties by comparing
to publicly available market data and valuation metrics for comparable entities.
Assessment of indicators of impairment related to the Eagle Ford Operated CGU
As discussed in notes 2 and 7 to the consolidated financial statements, the Company assesses its oil and gas properties by cash
generating unit (“CGU”) for indicators of impairment and impairment reversal at the end of each reporting period. These
indicators can be internal such as changes in estimated proved and probable oil and gas reserves (“CGU reserves cash flows”)
and internally estimated oil and gas resources (“CGU resources cash flows”), or external such as market conditions impacting
discount rates or market capitalization. The estimation of CGU reserves cash flows in the reserve report involves the expertise of
independent qualified reserve evaluators, who take into consideration assumptions related to forecasted production volumes,
royalty obligations, operating and capital costs and commodity prices (“CGU reserve report assumptions”). The estimation of
CGU resources cash flows involves the expertise of internal qualified reserve evaluators, who take into consideration
64
2023 / Annual Report / Baytex Energy
assumptions related to forecasted production volumes, royalty obligations, operating and capital costs and commodity prices
(collectively “CGU resource report assumptions”), in addition to the number and locations of development wells along with the
annual drilling timeline and pace. Based on the Company’s assessment of internal and external indicators of impairment, the
Company determined that impairment testing was not required for the Eagle Ford Operated CGU as of December 31, 2023.
We identified the assessment of indicators of impairment related to the Eagle Ford Operated CGU as a critical audit matter.
Indicators of impairment and impairment reversal such as changes in estimated CGU reserves cash flows and CGU resources
cash flows required the application of auditor judgement. A high degree of auditor judgment was required in evaluating the Eagle
Ford Operated CGU reserve report assumptions and CGU resource report assumptions, which were used in the assessment of
indicators of impairment. Additionally, the evaluation of the Company’s resource valuation metric derived from the CGU
resources cash flows required the involvement of valuation professionals with specialized skills and knowledge.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested
the operating effectiveness of certain internal controls related to the critical audit matter. This included controls related to:
•
•
the Company’s assessment of internal and external indicators of impairment for the Eagle Ford Operated CGU
the Company’s estimation of the Eagle Ford Operated CGU reserves cash flows and CGU resources cash flows and
related CGU reserve report assumptions and CGU resource report assumptions in addition to the number and locations
of development wells along with the annual drilling timeline and pace.
We evaluated the Company’s assessment of internal and external indicators of impairment for the Eagle Ford Operated CGU by
considering whether the quantitative and qualitative information in the analysis was consistent with external market and industry
data and the estimate of Eagle Ford Operated CGU reserves cash flows and CGU resources cash flows.
We evaluated the competence, capabilities and objectivity of the independent qualified reserve evaluators engaged by the
Company. We evaluated the methodology used by the independent qualified reserves evaluators to estimate Eagle Ford
Operated CGU reserves cash flows for compliance with the applicable regulatory standards. We compared 2023 actual
production volumes, royalty obligations, operating and capital costs to those assumptions used in the acquired reserve report
estimate of proved and probable reserves for the Eagle Ford Operated CGU to assess the Company’s ability to accurately
forecast. We assessed the forecasted commodity prices used in the estimate of the Eagle Ford Operated CGU reserves cash
flows by comparing them to those published by other reserve engineering companies. We assessed the forecasted production
volumes, royalty obligations, operating and capital costs assumptions used in the estimate of Eagle Ford Operated CGU
reserves cash flows by comparing them to historical results.
We evaluated the competence, capabilities and objectivity of the internal qualified reserve evaluators. We assessed the
forecasted production volumes, royalty obligations, operating and capital costs and commodity price assumptions for
development well locations in the Eagle Ford Operated CGU resource report by comparing to the CGU reserve report
assumptions for similar well locations in the Eagle Ford Operated CGU reserve report. We assessed the number and locations of
development wells in the Eagle Ford Operated CGU resource report by comparing to the number and locations of development
wells in the Eagle Ford Operated CGU full field development plan. We assessed the annual drilling timeline and pace in the
Eagle Ford Operated CGU resource report by comparing to the annual drilling timeline and pace in the Eagle Ford Operated
CGU reserve report.
We involved valuation professionals with specialized skills and knowledge, who assisted in evaluating the Company’s resource
valuation metric derived from the CGU resources cash flows by comparing to publicly available market data and valuation
metrics for comparable entities.
Impact of estimated oil and gas reserves on depletion expense related to oil and gas properties
As discussed in note 3 to the consolidated financial statements, the Company depletes its oil and gas properties using the unit-
of-production method by depletable area. Under such method, capitalized costs are depleted over estimated proved and
probable oil and gas reserves by depletable area (“area reserves”). As discussed in note 7 to the consolidated financial
statements, the Company recorded depletion expense related to oil and gas properties of $1,039.8 million for the year ended
December 31, 2023. The estimation of area reserves requires the expertise of independent qualified reserve evaluators who take
into consideration assumptions related to forecasted production volumes, royalty obligations, operating and capital costs and
commodity prices (collectively “area reserve report assumptions”). The Company engages independent qualified reserve
evaluators to estimate area reserves.
We identified the assessment of the impact of estimated area reserves on depletion expense related to oil and gas properties as
a critical audit matter. Changes in area reserve report assumptions could have had a significant impact on the calculation of
depletion expense of the depletable area. A high degree of auditor judgment was required in evaluating the area reserves, and
related area reserve report assumptions, which were used in the calculation of depletion expense.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested
the operating effectiveness of certain internal controls related to the critical audit matter. This included controls related to:
•
•
the Company’s calculation of depletion expense by depletable area
the Company’s determination of area reserve report assumptions and resulting area reserves.
2023 / Annual Report / Baytex Energy 65
We assessed the calculation of depletion expense for compliance with International Financial Reporting Standards as issued by
the International Accounting Standards Board. We evaluated the competence, capabilities and objectivity of the independent
qualified reserve evaluators engaged by the Company. We evaluated the methodology used by the independent qualified reserve
evaluators to estimate area reserves for compliance with the applicable regulatory standards. We compared the current year
actual production volumes, royalty obligations, operating and capital costs to those estimates used in the prior year estimate of
proved reserves to assess the Company’s ability to accurately forecast. We assessed the forecasted commodity prices used in
the estimate of area reserves by comparing them to those published by other reserves engineering companies. We assessed the
forecasted production volumes, royalty obligations, operating and capital costs assumptions used in the estimate of area
reserves by comparing them to historical results.
/s/ KPMG LLP
Chartered Professional Accountants
We have served as the Company’s auditor since 2016.
Calgary, Canada
February 28, 2024
66
2023 / Annual Report / Baytex Energy
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors of Baytex Energy Corp.
Opinion on Internal Control Over Financial Reporting
We have audited Baytex Energy Corp.’s (and subsidiaries’) (the “Company”) internal control over financial reporting as of
December 31, 2023, 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, 2023, 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 at December 31, 2023 and 2022, the related
consolidated statements of income (loss) and comprehensive income (loss), changes in equity, and cash flows for the years then
ended, and the related notes (collectively, the consolidated financial statements), and our report dated February 28, 2024
expressed an unqualified opinion on those consolidated financial statements.
The Company acquired Ranger Oil Corporation during 2023, and management excluded from its assessment of the
effectiveness of the Company’s internal control over financial reporting as of December 31, 2023, Ranger Oil Corporation’s
internal control over financial reporting associated with total assets of $3.5 billion and total revenues, net of royalties, of $691.9
million included in the consolidated financial statements of the Company as of and for the year ended December 31, 2023. Our
audit of internal control over financial reporting of the Company also excluded an evaluation of the internal control over financial
reporting of Ranger Oil Corporation.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual
Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control
over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be
independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and
regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all
material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control
over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we
considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that
(1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions
of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the
company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ KPMG LLP
Chartered Professional Accountants
Calgary, Canada
February 28, 2024
2023 / Annual Report / Baytex Energy 67
Baytex Energy Corp.
Consolidated Statements of Financial Position
(thousands of Canadian dollars)
As at
ASSETS
Current assets
Cash
Trade receivables
Prepaids and other assets
Financial derivatives
Non-current assets
Exploration and evaluation assets
Oil and gas properties
Other plant and equipment
Lease assets
Prepaids and other assets
Deferred income tax asset
LIABILITIES
Current liabilities
Trade payables
Share-based compensation liability
Dividends payable
Lease obligations
Asset retirement obligations
Non-current liabilities
Other long-term liabilities
Share-based compensation liability
Credit facilities
Long-term notes
Lease obligations
Asset retirement obligations
Deferred income tax liability
SHAREHOLDERS’ EQUITY
Shareholders' capital
Contributed surplus
Accumulated other comprehensive income
Deficit
Notes
December 31, 2023
December 31, 2022
$
55,815 $
$
$
18
18
6
7
15
15
12
11,18
10
12
8
9
10
15
11
339,405
21,530
23,274
440,024
90,919
6,619,033
7,936
28,145
61,729
213,145
7,460,931 $
477,295 $
28,508
18,381
13,391
20,448
558,023
19,147
7,224
848,749
1,562,361
16,056
602,951
21,333
3,635,844
6,527,289
193,077
690,917
(3,586,196)
3,825,087
5,464
222,108
6,377
10,105
244,054
168,684
4,620,766
6,568
6,453
—
57,244
5,103,769
227,332
44,863
—
3,521
12,813
288,529
—
9,209
383,031
547,598
3,017
576,110
265,858
2,073,352
5,499,664
89,879
756,195
(3,315,321)
3,030,417
5,103,769
$
7,460,931 $
Subsequent events (note 11 and note 18) and Commitments (note 20)
See accompanying notes to the consolidated financial statements.
/s/ Mark R. Bly
Mark R. Bly
/s/ Jennifer A. Maki
Jennifer A. Maki
Director, Baytex Energy Corp.
Director, Baytex Energy Corp.
68
2023 / Annual Report / Baytex Energy
Baytex Energy Corp.
Consolidated Statements of Income (Loss) and Comprehensive Income (Loss)
(thousands of Canadian dollars, except per common share amounts and weighted average common shares)
Years Ended December 31
Notes
2023
2022
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 loss (reversal)
Share-based compensation
Financing and interest
Financial derivatives (gain) loss
Foreign exchange (gain) loss
Loss (gain) on dispositions
Other (income) expense
Net (loss) income before income taxes
Income tax (recovery) expense
Current income tax expense
Deferred income tax (recovery) expense
Net (loss) income
Other comprehensive (loss) income
Foreign currency translation adjustment
Comprehensive (loss) income
Net (loss) income per common share
Basic
Diluted
Weighted average common shares
Basic
Diluted
See accompanying notes to the consolidated financial statements.
14
$
3,382,621 $
(669,792)
2,712,829
4
6
6, 7
12
16
18
17
15
13
13
$
$
$
$
570,839
89,306
224,802
69,789
49,045
8,896
1,047,904
833,662
37,699
192,173
(24,695)
(10,848)
141,295
(456)
3,229,411
(516,582)
14,403
(297,629)
(283,226)
(233,356) $
(65,278)
(298,634) $
(0.33) $
(0.33) $
704,896
704,896
2,889,045
(562,964)
2,326,081
422,666
48,561
189,454
50,270
—
30,239
587,050
(267,744)
29,056
104,817
199,010
43,441
(4,898)
3,244
1,435,166
890,915
3,594
31,716
35,310
855,605
124,092
979,697
1.53
1.52
557,986
563,835
2023 / Annual Report / Baytex Energy 69
Baytex Energy Corp.
Consolidated Statements of Changes in Equity
(thousands of Canadian dollars)
Balance at December 31, 2021
$
5,736,593 $
13,559 $
632,103 $
(4,170,926) $
2,211,329
Notes
Shareholders’
capital
Contributed
surplus
Accumulated
other
comprehensive
income
Deficit
Total equity
Vesting of share awards
Share-based compensation
Repurchase of common shares for
cancellation
Transfers for liability-classified awards
Comprehensive income
Balance at December 31, 2022
Issued on corporate acquisition
Vesting of share awards
Share-based compensation
Repurchase of common shares for
cancellation
Dividends declared
Comprehensive loss
11
12
4
11
12
11
11
8,501
—
(8,501)
3,159
(245,430)
86,453
—
—
(4,791)
—
—
—
—
—
—
—
—
—
3,159
(158,977)
(4,791)
979,697
—
124,092
855,605
$
5,499,664 $
89,879 $
756,195 $
(3,315,321) $
3,030,417
1,326,435
26,229
—
21,316
(37,462)
16,237
(325,039)
103,107
—
—
—
—
—
—
—
—
—
(65,278)
—
—
—
—
(37,519)
(233,356)
1,347,751
(11,233)
16,237
(221,932)
(37,519)
(298,634)
Balance at December 31, 2023
$
6,527,289 $
193,077 $
690,917 $
(3,586,196) $
3,825,087
See accompanying notes to the consolidated financial statements.
70
2023 / Annual Report / Baytex Energy
Baytex Energy Corp.
Consolidated Statements of Cash Flows
(thousands of Canadian dollars)
Years Ended December 31
Notes
2023
2022
CASH PROVIDED BY (USED IN):
Operating activities
Net (loss) income
Adjustments for:
Non-cash share-based compensation
Unrealized foreign exchange (gain) loss
Exploration and evaluation
Depletion and depreciation
Impairment loss (reversal)
Non-cash financing and accretion
Non-cash other income
Unrealized financial derivatives loss (gain)
Cash premiums on derivatives
Loss (gain) on dispositions
Deferred income tax (recovery) expense
Asset retirement obligations settled
Change in non-cash working capital
Cash flows from operating activities
Financing activities
Increase (decrease) in credit facilities
Decrease in acquired credit facilities
Debt issuance costs
Payments on lease obligations
Net proceeds from issuance of long-term notes
Redemption of long-term notes
Redemption of acquired long-term notes
Repurchase of common shares
Dividends declared
Change in non-cash working capital
Cash flows from (used in) financing activities
Investing activities
Additions to exploration and evaluation assets
Additions to oil and gas properties
Additions to other plant and equipment
Corporate acquisition, net of cash acquired
Property acquisitions
Proceeds from dispositions
Change in non-cash working capital
Cash flows used in investing activities
Change in cash
Cash, beginning of year
Cash, end of year
Supplementary information
Interest paid
Income taxes paid
$
(233,356) $
855,605
12
17
6
6, 7
16
10
18
15
10
19
8
4
9
9
4
11
11
19
6
7
4
19
16,237
(14,300)
8,896
1,047,904
833,662
32,350
(1,271)
11,517
(2,263)
141,295
(297,629)
(26,416)
(220,895)
1,295,731
477,387
(373,608)
(40,424)
(11,527)
1,046,197
—
(569,256)
(221,932)
(37,519)
(3,068)
266,250
—
(1,012,787)
(4,416)
(662,579)
(38,914)
160,256
46,810
(1,511,630)
50,351
5,464
55,815 $
153,224 $
3,603 $
$
$
$
3,159
45,073
30,239
587,050
(267,744)
24,431
(4,009)
(135,471)
—
(4,898)
31,716
(18,351)
26,072
1,172,872
(136,980)
—
(2,138)
(3,732)
—
(376,589)
—
(158,977)
—
—
(678,416)
(6,359)
(515,183)
(1,148)
—
(1,352)
25,649
9,401
(488,992)
5,464
—
5,464
84,225
2,303
See accompanying notes to the consolidated financial statements.
2023 / Annual Report / Baytex Energy
71
Baytex Energy Corp.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2023 and 2022
(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 energy company engaged in the acquisition, development and
production of oil and natural gas in the Western Canadian Sedimentary Basin and in Texas, United States. The Company’s
common shares are traded on the Toronto Stock Exchange 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 PREPARATION
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 material accounting policies set forth
below were consistently applied to all periods presented.
The consolidated financial statements were approved by the Board of Directors of Baytex on February 28, 2024.
The consolidated financial statements have been prepared on a historical cost basis, with the exception of certain fair value
measurements noted in the material accounting policies set forth below. The consolidated financial statements are presented in
Canadian dollars which is the functional currency of the Company. References to “US$” are to United States ("U.S.") dollars. All
financial information is rounded to the nearest thousand, except per share amounts or where otherwise indicated.
Certain prior year amounts have been reclassified to conform to current year presentation, including prepaids and other assets
and share-based compensation liability.
Measurement Uncertainty and Judgments
Management makes judgements and assumptions about the future in deriving estimates used in preparation of these
consolidated financial statements in accordance with IFRS. Sources of estimation uncertainty include estimates used to
determine economically recoverable oil, natural gas, and natural gas liquids reserves, the recoverable amount of long-lived
assets or cash generating units, the fair value of financial derivatives, the provision for asset retirement obligations and the
provision for income taxes and the related deferred tax assets and liabilities.
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, including
considerations related to various regulatory and legislative requirements, to the Company at the time of financial statement
preparation. Actual results could be materially different from those estimates as the effect of future events cannot be determined
with certainty. Revisions to estimates are recognized prospectively. 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,
evaluating the recoverability of deferred income tax assets and in the determination of recoverable 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 qualified reserves evaluators and represent the estimated recoverable
quantities of oil, natural gas and NGL reserves and the related 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 reserves and the related cash flows are based on a number of
factors and assumptions. Changes to estimates and assumptions such as forecasted commodity prices, production volumes,
capital and operating costs and royalty obligations could have a significant impact on reported reserves. Other estimates include
ultimate reserve recovery, marketability of oil and natural gas and other geological, economic and technical factors. Changes in
the Company's reserves estimates can have a significant impact on the calculation of depletion, the recoverability of deferred
income tax assets and in the determination of recoverable value estimates for non-financial assets.
72
2023 / Annual Report / Baytex Energy
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. The determination of the fair value assigned to assets acquired and liabilities
assumed requires management to make assumptions and estimates. These 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. The
determination of the acquisition-date fair value measurement of oil and gas properties acquired represents the largest fair value
estimate which is derived from the present value of expected cash flows associated with estimated acquired proved and
probable oil and gas reserves prepared by an independent qualified reserve evaluator using assumptions as outlined under
"reserves", on an after-tax basis and applying a discount rate. Assumptions used to arrive at the fair value of oil and gas
properties are further verified by way of market comparisons and third party sources.
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 inflows that are largely independent of the cash inflows 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. These indicators can be internal such as changes in
estimated proved and probable oil and gas reserves ("CGU reserves") and internally estimated oil and gas resources, or external
such as market conditions impacting discount rates or market capitalization. The assessment for each CGU considers significant
changes in the forecasted cash flows including reservoir performance, the number of development locations and timing of
development, forecasted commodity prices, production volumes, capital and operating costs and royalty obligations.
Measurement of Recoverable Amounts
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 and probable oil and gas reserves and the
discount rate used to present value future cash flows. Any changes to these estimates and assumptions could impact the
calculation of the recoverable amount and the carrying value of assets.
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 risk-free discount rates and
inflation rates. The Company uses risk-free discount 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.
Income Taxes
Tax regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to
change and there are differing interpretations requiring management judgment. Income tax filings are subject to audit and re-
assessment and changes in facts, circumstances and interpretations of the applicable legislative requirements may result in a
material change to the Company's provision for income taxes.
Environmental Reporting Regulations
Environmental reporting for public enterprises continues to evolve and the Company may be subject to additional future
disclosure requirements. The International Sustainability Standards Board has issued an IFRS Sustainability Disclosure
Standard with the objective to develop a global framework for environmental sustainability disclosure. The Canadian Securities
Administrators have also issued a proposed National Instrument 51-107 Disclosure of Climate-related Matters which sets forth
additional reporting requirements for Canadian Public Companies. Baytex continues to monitor developments on these reporting
requirements and has not yet quantified the cost to comply with these regulations.
2023 / Annual Report / Baytex Energy 73
3. MATERIAL ACCOUNTING POLICIES
Consolidation
The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. Subsidiaries are
entities controlled by the Company. Control exists when the Company has the power to govern the financial and operating
policies to obtain benefits from its activities. Significant subsidiaries included in the Company's accounts include Baytex Energy
USA, Inc., Baytex Energy Ltd. and Baytex Energy Limited Partnership. Intercompany transactions are eliminated in preparation
of the consolidated financial statements.
Many of the Company's exploration, development and production activities are conducted through jointly owned assets. The
consolidated financial statements include the Company's proportionate share of the assets, liabilities, revenues and expenses
generated by jointly owned assets.
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 and it is physically transferred to the customer at the agreed upon delivery point.
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 is based on a representative commodity price index, and typically includes
adjustments for quality, location, delivery method, or other factors depending on the agreed upon terms of the contract. The
amount of revenue recorded varies 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 ("E&E") Assets
Once the legal right to explore has been acquired, costs directly associated with an exploration program are capitalized as E&E
assets 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 expenditures are costs incurred in an area where technical feasibility and commercial viability has not yet been determined.
The technical feasibility and commercial viability is dependent on whether extracting petroleum and natural gas resources is
demonstrable. If the asset is determined not to be technically feasible or commercially viable the accumulated E&E assets
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 demonstrating the ability to extract mineral
resources 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
Oil and gas properties are initially recorded at cost and include the costs to acquire, develop, complete geological and
geophysical surveys, drill and complete wells for production, and construct and install infrastructure including 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 economic benefits of the replacement will be realized by the
Company in the future. 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.
74
2023 / Annual Report / Baytex Energy
Depletion
The costs associated with oil and gas properties are depleted on a unit-of-production basis by depletable area over proved and
probable reserves once commercial production has commenced. Forecasted capital costs required to bring proved and probable
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.
Impairment and Impairment Reversals
Non-financial Assets
The Company reviews its oil and gas properties and E&E assets at a CGU level for indicators of impairment and impairment
reversal at the end of each reporting period. E&E assets are also assessed for impairment upon transfer to oil and gas
properties. The recoverable amount of the asset is estimated if indicators of impairment or impairment reversal exist.
When reviewing for indicators of impairment or impairment reversal, and testing for impairment or impairment reversal when
indicators have been identified, assets are grouped together at a CGU level. The recoverable amount of an asset or CGU is the
higher of its FVLCD and its VIU. The determination of recoverable amount includes estimates of proved and probable oil and gas
reserves and the associated cash flows. Factors that impact these cash flows include forecasted CGU production volumes,
royalty obligations, operating costs, capital costs, commodity prices, taxes, along with inflation and discount rates used to
estimate present value. FVLCD is the amount that would be obtained from the sale of an asset or CGU in an arm's length
transaction. In determining FVLCD, recent comparable market transactions are considered if available. In the absence of such
transactions, an appropriate valuation model is used. VIU is assessed using the present value of the estimated future cash flows
of the asset or CGU. The estimated future cash flows are adjusted for risks specific to the asset or CGU and are discounted
using a discount rate based on the Company’s weighted average cost of capital adjusted for risks specific to the CGU.
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 the individual assets in the CGU on a pro-rata basis.
Impairments may be reversed for all CGUs and individual assets 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 CGU’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.
Impairments and impairment reversals are recorded in net income or loss in the period the impairment or impairment reversal
occurs.
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, discounted using the risk-free
interest rate. The present value of the liability is capitalized as part of the cost of the related asset and depleted over its useful
life. The asset retirement obligation is accreted until the date of expected settlement of the retirement obligation and is
recognized within financing and interest expense in net 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.
2023 / Annual Report / Baytex Energy 75
Foreign Operations
The functional currency of the Company's subsidiaries is the currency of the primary economic environment in which the entity
operates. The Company's U.S. operations are conducted in USD. Management judgement is required in the designation of a
subsidiary's functional currency.
The financial statements of each entity are translated into Canadian dollars during the preparation of the Company's
consolidated financial statements. Refer to the Consolidation section of Note 3 for a list of the Company's entities. The assets
and liabilities of a foreign operation are translated to Canadian dollars at the period-end exchange rate. Revenues and expenses
of foreign operations are translated to Canadian dollars using the average exchange rate for the period. Foreign exchange
differences are recognized in other comprehensive income or loss.
If the Company or any of its entities disposes of its entire interest in a foreign operation, or loses control, joint control, or
significant influence over a foreign operation, the accumulated foreign currency translation gains or losses related to the foreign
operation are recognized in net income or loss.
Financial Instruments
Financial assets are initially classified into two categories: measured at amortized cost or fair value through profit or loss
(“FVTPL”).
The measurement category for each class of financial asset and financial liability is set forth in the following table.
Financial Instrument
Cash
Trade receivables
Financial derivatives
Trade payables
Dividends payable
Credit facilities
Long-term notes
Classification
Amortized cost
Amortized cost
Fair value through profit or loss
Amortized cost
Amortized cost
Amortized cost
Amortized cost
Debt issuance costs related to the amendment of the Company's credit facilities or the issuance of long-term notes are
capitalized and amortized as financing costs over the term of the credit facilities or long-term notes. For a financial asset or a
financial liability carried at amortized cost, transaction costs directly attributable to acquiring or issuing the asset or liability are
added to, or deducted from, the fair value on initial recognition and amortized through net income or loss over the term of the
financial instrument. Transaction costs that are directly attributable to the acquisition or issue of a financial asset or a financial
liability classified as FVTPL are expensed at inception of the contract.
The Company formally documents its risk management objectives and strategies to manage exposures to fluctuations in
commodity prices, interest rates and foreign currency exchange rates. The 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. 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 accounts for its physical delivery sales contracts as executory contracts. These contracts are entered into and
held for the purpose of receipt or delivery of non-financial items in accordance with its expected purchase, sale or usage
requirements. As such, these contracts are not considered to be derivative financial instruments and are not 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.
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 upheld. The asset or liability is
measured based on an assessment of probable outcomes and their associated probabilities.
76
2023 / Annual Report / Baytex Energy
The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred income taxes
are recorded for the effect of any temporary differences between the carrying amounts of assets and liabilities in the consolidated
financial statements and the corresponding tax basis used in the computation of taxable income. Deferred income tax liabilities
are generally recognized for all taxable temporary differences. Deferred income tax assets are recognized for all deductible
temporary differences 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 or increased to the extent that it is no longer probable or becomes 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.
Tax regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to
change and there are differing interpretations requiring management judgment. Deferred tax assets are recognized when it is
considered probable that deductible temporary differences will be recovered in future periods, which requires management
judgment. Deferred tax liabilities are recognized when it is considered probable that temporary differences will be payable to tax
authorities in future periods, which requires management judgment. Income tax filings are subject to audit and re-assessment
and changes in facts, circumstances and interpretations of the standards may result in a material change to the Company's
provision for income taxes.
New Accounting Standards Adopted
In 2023, Baytex adopted amendments to IAS 12 Income Taxes regarding relief from deferred tax accounting for top-up tax under
Pillar Two. Pillar Two refers to a minimum 15% tax rate on the income generated by multinational corporations in the jurisdictions
in which they operate. Baytex applies the exception to recognizing and disclosing information about deferred taxes related to
Pillar Two income taxes, as provided in the amendments to IAS 12 issued in May 2023. This amendment did not have a material
impact on our consolidated financial statements.
Baytex has adopted amendments to IAS 1 Presentation of Financial Statements regarding the disclosure of material accounting
policies, effective January 1, 2023. This amendment was disclosure related and did not impact the Company's accounting
policies.
Future Accounting Pronouncements
Effective January 1, 2024, Baytex plans to adopt amendments to IAS 1 Presentation of Financial Statements which was issued
by the IASB in January 2020. The amendments further clarify the requirements for the presentation of liabilities as current or
non-current in the consolidated statements of financial position.
In October 2022, the IASB issued Non-current Liabilities with Covenants which amended IAS 1 Presentation of Financial
Statements. The amendments specify the classification and disclosure of a liability with covenants and is effective January 1,
2024.
These amendments are not expected to have a material impact on our consolidated financial statements.
4. BUSINESS COMBINATION
On June 20, 2023, Baytex closed the acquisition of Ranger Oil Corporation (“Ranger”), a publicly traded oil and gas exploration
and production company with operations in the Eagle Ford. Baytex acquired all of the issued and outstanding common shares of
Ranger and is treated as the acquirer for accounting purposes. The acquisition increases Baytex's Eagle Ford scale and
provides an operating platform to effectively allocate capital across the Western Canadian Sedimentary Basin and the Eagle
Ford.
The acquisition was accounted for as a business combination with the net assets and liabilities recorded at fair value at the
acquisition date. The total consideration of US$1.6 billion ($2.1 billion) consisted of $732.8 million of cash consideration and
311.4 million Baytex common shares valued at approximately $1.3 billion (based on the closing price of Baytex’s common shares
of $4.26 per share on the Toronto Stock Exchange on June 20, 2023). Under the terms of the agreement, Ranger shareholders
received 7.49 Baytex shares plus US$13.31 cash for each share of Ranger common stock.
The fair value of oil and gas properties acquired is primarily based on estimated cash flows associated with proved and probable
oil and gas reserves acquired and the discount rate. Factors that impact these reserves cash flows include forecasted production
volumes, royalty obligations, operating and capital costs, taxes and commodity prices. The estimation of reserves cash flows
involves the expertise of the independent qualified reserve evaluators. Any changes to these estimates and assumptions could
impact the calculation of the recoverable amount and the carrying value of assets. The fair value of the acquired oil and gas
properties were determined using a discount rate of 12.2%.
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 rate of interest of 9.0%.
2023 / Annual Report / Baytex Energy 77
The total consideration paid and estimates of the fair value of the assets and liabilities acquired as at the date of the acquisition
are set forth in the table below. The preliminary purchase price equation is based on Management's best estimate of the assets
acquired and liabilities assumed. Adjustments to these initial estimates may be required upon finalizing the value of net assets
acquired.
USD
CAD (1)
Consideration
Cash
Common shares issued
Share based compensation (2)
Total consideration
Fair value of net assets acquired
Oil and gas properties (3)
Working capital deficiency excluding bank debt and financial derivatives (3)(4)
Financial derivatives
Lease assets
Lease obligations
Credit facilities
Long-term notes
Asset retirement obligations
Deferred income tax asset (3)
Net assets acquired
$
$
$
553,150 $
1,001,196
20,107
1,574,453 $
2,337,173 $
(120,565)
17,030
15,708
(15,708)
(282,000)
(429,676)
(23,632)
76,123
732,840
1,326,435
26,638
2,085,913
3,096,404
(159,731)
22,562
20,811
(20,811)
(373,608)
(569,256)
(31,310)
100,852
$
1,574,453 $
2,085,913
(1) Exchange rate used to translate the U.S. denominated values above is the rate as at the closing date being CAD/USD 1.32485.
(2) Following closing of the transaction, holders of awards outstanding under Ranger's share based compensation plans are entitled to Baytex
common shares rather than Ranger common shares with adjustment to the quantity outstanding based on the exchange ratio for Ranger
shares. The fair value of share awards allocated to consideration was based on the service period that had occurred prior to the acquisition
date while the remaining fair value of the share awards assumed by Baytex will be recognized over the remaining future service periods
(note 12). Included in this balance is $21.3 million (US$16.1 million) of awards that were fully vested at close of the Ranger acquisition and
$5.3 million (US$4.0 million) of cash-based awards included in share-based compensation liability.
(3) Adjustments were recorded to the preliminary fair value to reflect circumstances that existed as at the acquisition date. These adjustments
relate to an update in operating results which increased our working capital deficiency by $16.4 million (US$12.4 million) with an offset to oil
and gas properties and an increase in the deferred income tax asset of $1.6 million (US$1.2 million) as a result.
Includes $70.3 million (US$53.0 million) of cash. Trade receivables acquired is net of a provision for expected credit losses of approximately
$0.3 million.
(4)
The cash portion of the transaction was funded with Baytex’s expanded credit facility which increased to US$1.1 billion at close
of the transaction, US$150 million from a two-year term loan facility, and the net proceeds from the issuance of US$800 million
senior unsecured notes due 2030. Baytex closed the US$800 million, senior unsecured note offering on April 27, 2023 and the
net proceeds were released from escrow on June 20, 2023.
These consolidated financial statements include the results of operations of Ranger for the period following closing of the
transaction on June 20, 2023. For the year ended December 31, 2023, the acquisition contributed revenues and net income
before income taxes of $939.4 million and $165.1 million, respectively. Had the acquisition occurred on January 1, 2023,
revenues and net income before income taxes would have increased by approximately $1.7 billion and $366.7 million,
respectively, for the year ended December 31, 2023. This pro-forma information is not necessarily indicative of the results of
operations that would have resulted had the acquisition been reflected on the dates indicated, or that may be obtained in the
future.
During the year ended December 31, 2023, Baytex incurred transaction costs of $49.0 million. Transaction costs include
consulting, advisory fees, legal fees, tax fees and other professional fees of $41.7 million, as well as post-combination employee-
related costs of $7.3 million.
78
2023 / Annual Report / Baytex Energy
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
2023
2022
2023
2022
2023
2022
2023
2022
Canada
U.S.
Corporate
Consolidated
Revenue, net of royalties
Petroleum and natural gas sales
$ 1,729,021 $ 1,926,561 $ 1,653,600 $ 962,484 $
— $
— $ 3,382,621 $ 2,889,045
Royalties
Expenses
Operating
Transportation
Blending and other
General and administrative
Transaction costs
Exploration and evaluation
Depletion and depreciation
Impairment loss (reversal)
Share-based compensation
Financing and interest
Financial derivatives (gain) loss
Foreign exchange (gain) loss
Loss (gain) on dispositions
Other (income) expense
(213,148)
(277,428)
(456,644)
(285,536)
1,515,873
1,649,133
1,196,956
676,948
368,605
327,894
202,234
94,772
64,325
48,561
24,981
224,802
189,454
—
—
—
—
8,896
30,239
—
—
—
—
—
—
—
—
—
484,232
409,286
555,548
171,747
184,000
(267,744)
649,662
—
—
—
—
—
—
—
—
141,295
(1,271)
(4,898)
(4,009)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
69,789
49,045
—
8,124
—
—
—
—
—
—
50,270
—
—
(669,792)
(562,964)
2,712,829
2,326,081
570,839
422,666
89,306
48,561
224,802
189,454
69,789
49,045
8,896
50,270
—
30,239
6,017
1,047,904
587,050
—
833,662
(267,744)
37,699
29,056
37,699
29,056
192,173
104,817
192,173
104,817
(24,695)
199,010
(24,695)
199,010
(10,848)
43,441
(10,848)
43,441
—
815
—
141,295
7,253
(456)
(4,898)
3,244
Net income (loss) before income taxes
40,989
920,350
(235,469)
410,429
(322,102)
(439,864)
(516,582)
890,915
1,474,884
728,783
1,432,425
266,519
322,102
439,864
3,229,411
1,435,166
Income tax (recovery) expense
Current income tax expense
Deferred income tax (recovery) expense
14,403
(297,629)
(283,226)
3,594
31,716
35,310
Net income (loss)
$
40,989 $ 920,350 $ (235,469) $ 410,429 $ (322,102) $ (439,864) $ (233,356) $ 855,605
Additions to exploration and evaluation
assets
—
6,359
—
—
Additions to oil and gas properties
463,198
374,443
549,589
140,740
Corporate acquisition, net of cash
acquired
—
—
662,579
Property acquisitions
20,023
1,352
18,891
Proceeds from dispositions
(160,256)
(25,649)
—
As at
Canadian assets
U.S. assets
Corporate assets
Total consolidated assets
—
—
—
$
$
—
—
—
—
—
—
—
—
—
—
—
6,359
1,012,787
515,183
662,579
—
38,914
1,352
(160,256)
(25,649)
December 31, 2023
December 31, 2022
2,289,083 $
5,112,493
59,355
7,460,931 $
2,779,596
2,301,047
23,126
5,103,769
2023 / Annual Report / Baytex Energy 79
6. EXPLORATION AND EVALUATION ASSETS
December 31, 2023
December 31, 2022
Balance, beginning of year
$
168,684 $
Capital expenditures
Property acquisitions
Divestitures
Property swaps
Impairment reversal
Exploration and evaluation expense
Transfers to oil and gas properties (note 7)
Foreign currency translation
Balance, end of year
—
18,486
(2,965)
1,000
—
(8,896)
(83,530)
(1,860)
$
90,919 $
172,824
6,359
301
(498)
385
22,503
(30,239)
(8,496)
5,545
168,684
At December 31, 2023, there were no indicators of impairment or impairment reversal for exploration and evaluation assets in
any of the Company's CGUs.
At December 31, 2022, the Company identified indicators of impairment reversal for the exploration and evaluation assets within
the Peace River CGU due to an increase in land sale values. The recoverable amount for the Peace River CGU exceeded its
carrying value and an impairment reversal of $22.5 million was recorded at December 31, 2022. The recoverable amount was
based on the CGUs FVLCD and was estimated with reference to arm's length transactions in comparable locations.
7. OIL AND GAS PROPERTIES
Balance, December 31, 2021
Capital expenditures
Property acquisitions
Transfers from exploration and evaluation assets (note 6)
Change in asset retirement obligations (note 10)
Divestitures
Impairment reversal
Foreign currency translation
Depletion
Balance, December 31, 2022
Capital expenditures
Corporate acquisition (note 4)
Property acquisitions
Transfers from exploration and evaluation assets (note 6)
Transfers from lease assets
Change in asset retirement obligations (note 10)
Divestitures
Property swaps
Impairment loss
Foreign currency translation
Depletion
Balance, December 31, 2023
Accumulated
Cost
depletion Net book value
$
11,633,517 $
(7,169,146) $
4,464,371
515,183
1,173
8,496
(147,020)
(265,166)
—
296,033
—
—
—
—
—
241,892
245,241
(158,404)
(581,033)
515,183
1,173
8,496
(147,020)
(23,274)
245,241
137,629
(581,033)
$
12,042,216 $
(7,421,450) $
4,620,766
1,012,787
3,096,404
20,263
83,530
7,611
54,166
(660,920)
(2,975)
—
(127,065)
—
—
—
—
—
—
317,651
3,756
(833,662)
66,501
1,012,787
3,096,404
20,263
83,530
7,611
54,166
(343,269)
781
(833,662)
(60,564)
—
(1,039,780)
(1,039,780)
$
15,526,017 $
(8,906,984) $
6,619,033
80
2023 / Annual Report / Baytex Energy
At December 31, 2023, there were no indicators of impairment or impairment reversal for oil and gas properties in five CGUs and
no impairment testing was required, including for the Eagle Ford Operated CGU which includes the assets acquired from Ranger
(note 4).
2023 Impairment
At December 31, 2023, the Company identified indicators of impairment for oil and gas properties in two CGUs due to changes in
reserves volumes and a loss recorded on a disposition of an asset within an existing CGU. The recoverable amounts for the two
CGUs were not sufficient to support their carrying values which resulted in an impairment of $833.7 million recorded at
December 31, 2023. The recoverable amount for each CGU is based on estimated cash flows associated with proved and
probable oil and gas reserves from an independent reserve report prepared as at December 31, 2023 utilizing a discount rate
based on Baytex's corporate weighted average cost of capital adjusted for asset specific factors. The after-tax discount rates
applied to the cash flows were between 12% and 14%.
At December 31, 2023, the recoverable amounts of the two CGUs were calculated using the following benchmark reference
prices for the years 2024 to 2033 adjusted for commodity differentials specific to the CGU. The prices and costs subsequent to
2033 have been adjusted for inflation at an annual rate of 2.0%.
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
WTI crude oil (US$/bbl)
73.67
74.98
76.14
77.66
79.22
80.80
82.42
84.06
85.74
87.46
LLS crude oil (US$/bbl)
76.49
77.80
78.95
80.35
81.95
83.59
85.27
86.97
88.71
90.48
Edmonton par oil ($/bbl)
92.91
95.04
96.07
97.99
99.95 101.94 103.98 106.06 108.18 110.35
NYMEX Henry Hub gas (US$/
mmbtu)
AECO gas ($/mmbtu)
Exchange rate (CAD/USD)
2.75
2.20
0.75
3.64
3.37
0.75
4.02
4.05
0.76
4.10
4.13
0.76
4.18
4.21
0.76
4.27
4.30
0.76
4.35
4.38
0.76
4.44
4.47
0.76
4.53
4.56
0.76
4.62
4.65
0.76
The following table summarizes the recoverable amount and impairment for each of the two CGUs at December 31, 2023 and
demonstrates the sensitivity of the impairment to reasonably possible changes in key assumptions inherent in the calculation.
Recoverable
amount
Impairment loss Change in discount
rate of 1%
Change in oil price
of $2.50/bbl
Change in gas
price of $0.25/mcf
Viking CGU
Eagle Ford Non-op CGU (1)
$
606,290 $
184,000 $
1,429,658
649,662
26,500 $
71,300
53,000 $
107,600
3,500
25,700
(1) There were no indicators of impairment identified for the Eagle Ford Operated CGU which includes the assets acquired from Ranger (note
4).
2022 Impairment Reversal
At December 31, 2022, indicators of impairment reversal were identified for oil and gas properties in five CGUs due to the
increase in forecasted commodity prices in addition to changes in reserves volumes. The recoverable amount for three CGUs
exceeded their carrying values which resulted in an impairment reversal of $245.2 million recorded at December 31, 2022. The
recoverable amount for each CGU is based on estimated cash flows associated with proved and probable oil and gas reserves
from an independent reserve report prepared as at December 31, 2022 with a discount rate based on Baytex's corporate
weighted average cost of capital adjusted for asset specific factors. The after-tax discount rates applied to the cash flows were
between 12% and 23%.
The following table summarizes the recoverable amount and impairment reversal for each of the five CGUs at December 31,
2022 and demonstrates the sensitivity of the impairment reversal to reasonably possible changes in key assumptions inherent in
the calculation.
Recoverable
amount
Impairment
reversal
Change in discount
rate of 1%
Change in oil price
of $2.50/bbl
Change in gas
price of $0.25/mcf
Conventional CGU (1)
Peace River CGU (1)
Lloydminster CGU
Viking CGU
Eagle Ford Non-op CGU
$
119,031 $
23,707 $
676,939
449,250
1,322,193
2,102,646
140,534
—
81,000
—
— $
—
11,500
39,500
95,800
— $
—
53,000
78,000
131,100
—
—
—
4,000
28,500
(1) The impairment reversals for the Conventional and Peace River CGUs were limited to the total accumulated impairments less subsequent
depletion of $23.7 million and $140.5 million, respectively. As a result, changes in the key assumptions presented in the table above have
no impact on the amount of the impairment reversal as at December 31, 2022.
2023 / Annual Report / Baytex Energy 81
8. CREDIT FACILITIES
Credit facilities - U.S. dollar denominated (1)
Credit facilities - Canadian dollar denominated
Credit facilities - principal (2)
Unamortized debt issuance costs
Credit facilities
December 31, 2023
December 31, 2022
$
$
$
311,980 $
552,756
864,736 $
(15,987)
848,749 $
30,394
355,000
385,394
(2,363)
383,031
(1) U.S. dollar denominated credit facilities balance was US$236.3 million as at December 31, 2023 (December 31, 2022 - US$22.5 million).
(2) The increase in the principal amount of the credit facilities outstanding from December 31, 2022 to December 31, 2023 is the result of net draws
of $477.4 million along with an increase in the reported amount of U.S. denominated debt of $2.0 million due to foreign exchange.
At December 31, 2023, Baytex had US$1.1 billion ($1.5 billion) of revolving credit facilities (the "Credit Facilities"). On June 20,
2023, in connection with the acquisition of Ranger, Baytex amended its Credit Facilities to increase the committed amount to
$1.1 billion ($1.5 billion) (previously US$850 million in aggregate as of April 1, 2022). The maturity date of the Credit Facilities is
April 1, 2026. Baytex also entered into a secured two-year term loan of US$150 million that was repaid and cancelled in August
2023.
The Credit Facilities are secured and are comprised of a US$50 million operating loan and a US$750 million syndicated
revolving loan for Baytex and a US$45 million operating loan and a US$255 million syndicated revolving loan for Baytex's wholly-
owned subsidiary, Baytex Energy USA, Inc. The amended Credit Facilities contain an additional financial covenant of a maximum
Total Debt to Bank EBITDA ratio of 4.0:1.0 and increased the Interest Coverage minimum ratio to 3.5:1.0 (from 2.0:1.0).
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 by Baytex. Advances 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 secured overnight financing rates ("SOFR"), plus applicable margins.
The weighted average interest rate on the Credit Facilities was 7.6% for the year ended December 31, 2023 (3.6% for the year
ended December 31, 2022).
The following table summarizes the financial covenants applicable to the Credit Facilities and the Company's compliance
therewith at December 31, 2023.
Covenant Description
Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio)
Interest Coverage (3) (Minimum Ratio)
Total Debt (4) to Bank EBITDA (2) (Maximum Ratio)
Position as at
December 31, 2023
0.4:1.0
11.3:1.0
1.1:1.0
Covenant
3.5:1.0
3.5:1.0
4.0:1.0
(1)
(2)
(3)
(4)
"Senior Secured Debt" is calculated in accordance with the credit facility agreement and is defined as the principal amount of the Credit
Facilities and other secured obligations identified in the credit facility agreement. As at December 31, 2023, the Company's Senior Secured
Debt totaled $864.7 million.
"Bank EBITDA" is calculated based on terms and definitions set out in the credit facility agreement which adjusts net income or loss for
financing and interest expenses, income tax, non-recurring losses, certain specific unrealized and non-cash transactions 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 year ended December 31, 2023 was $2.2 billion.
"Interest coverage" is calculated in accordance with the credit facility agreement and is computed as the ratio of Bank EBITDA to financing
and interest expenses, excluding certain non-cash transactions, and is calculated 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. Financing and interest expenses for the year
ended December 31, 2023 was $195.2 million.
"Total Debt" is calculated in accordance with the credit facility agreement and is defined as all obligations, liabilities, and indebtedness of
Baytex excluding trade payables, share-based compensation liability, dividends payable, asset retirement obligations, leases, deferred
income tax liabilities, other long-term liabilities and financial derivative liabilities. As at December 31, 2023, the Company's Total Debt
totaled $2.5 billion of principal amounts outstanding.
At December 31, 2023, Baytex had $5.6 million of outstanding letters of credit, $4.7 million of which is under a $20 million
uncommitted unsecured demand revolving letter of credit facility (December 31, 2022 - $15.7 million outstanding). Letters of
credit under this facility are guaranteed by Export Development Canada and do not use capacity available under the Credit
Facilities.
82
2023 / Annual Report / Baytex Energy
9. LONG-TERM NOTES
8.75% notes due April 1, 2027 (1)
8.50% notes due April 30, 2030 (2)
Total long-term notes - principal (3)
Unamortized debt issuance costs
Total long-term notes - net of unamortized debt issuance costs
December 31, 2023
December 31, 2022
$
$
$
541,114 $
1,056,361
1,597,475 $
(35,114)
1,562,361 $
554,597
—
554,597
(6,999)
547,598
(1) The U.S. dollar denominated principal outstanding of the 8.75% notes was US$409.8 million at December 31, 2023 (December 31, 2022 -
US$409.8 million).
(2) The U.S. dollar denominated principal outstanding of the 8.50% notes was US$800.0 million at December 31, 2023 (December 31, 2022 - nil).
(3) The increase in the principal amount of long-term notes outstanding from December 31, 2022 to December 31, 2023 is the result of the
issuance of the 8.50% notes for $1.1 billion and includes changes in the reported amount of U.S. denominated debt of $17.0 million due to
changes in the CAD/USD exchange rate used to translate the U.S. denominated amount of long-term notes outstanding.
On April 27, 2023, we issued US$800 million aggregate principal amount of senior unsecured notes due April 30, 2030 bearing
interest at a rate of 8.50% per annum semi-annually (the "8.50% Senior Notes"). The 8.50% Senior Notes were issued at
98.709% of par and are redeemable at our option, in whole or in part, at specified redemption prices after April 30, 2026 and will
be redeemable at par from April 30, 2028 to maturity. Net proceeds of $1.0 billion reflects $13.7 million for the original issue
discount and Baytex also incurred transaction costs of $18.5 million in conjunction with the issuance.
The long-term notes do not contain any significant financial maintenance covenants but do contain standard commercial
covenants for debt incurrence and restricted payments.
10. ASSET RETIREMENT OBLIGATIONS
Balance, beginning of year
Liabilities incurred (1)
Liabilities settled
Liabilities assumed from corporate acquisition (note 4)
Liabilities acquired from property acquisitions
Liabilities divested
Property swaps
Accretion (note 16)
Government grants (2)
Change in estimate (1)
Changes in discount rates and inflation rates (1)(3)
Foreign currency translation
Balance, end of year
Less current portion of asset retirement obligations
Non-current portion of asset retirement obligations
December 31, 2023
December 31, 2022
$
588,923 $
24,185
(26,416)
31,310
11
(43,153)
76
20,406
(1,271)
17,067
12,914
(653)
623,399 $
20,448
602,951 $
$
$
743,683
19,942
(18,351)
—
950
(3,464)
—
15,683
(4,009)
6,124
(173,086)
1,451
588,923
12,813
576,110
(1) The total of these items reflects the total change in asset retirement obligations of $54.2 million per Note 7 - Oil and Gas Properties ($147
million decrease in 2022).
(2) During 2023, Baytex recognized $1.3 million of non-cash other income and a reduction in asset retirement obligations related to government
grants provided by the Government of Alberta and the Government of Saskatchewan ($4.0 million in 2022).
(3) The discount and inflation rates used to calculate the liability for our Canadian operations at December 31, 2023 were 3.0% and 1.6%
respectively (December 31, 2022 - 3.3% and 2.1%). The discount and inflation rates used to calculate the liability for our U.S. operations at
December 31, 2023 were 4.0% and 2.1%, respectively (December 31, 2022 - 3.3% and 2.1%). The changes in discount rates also includes
the remeasurement of the liability acquired from Ranger from a market rate of interest on the date of acquisition to a risk-free rate at period
end.
At December 31, 2023, the undiscounted, uninflated amount of estimated cash flows required to settle the asset retirement
obligations is $795.5 million (December 31, 2022 - $724.8 million). The discounted amount of estimated cash flow required to
settle the asset retirement obligations at December 31, 2023 is $623.4 million (December 31, 2022 - $588.9 million). This was
calculated using an estimated inflation rate of 1.6% and 2.1% for Canadian and U.S. operations, respectively (December 31,
2022 - 2.1%) and a risk-free discount rate of 3.0% and 4.0% for Canadian and U.S. operations, respectively (December 31, 2022
- 3.3%). These costs are expected to be incurred over the next 60 years.
2023 / Annual Report / Baytex Energy 83
11. SHAREHOLDERS' CAPITAL
The authorized capital of Baytex consists of an unlimited number of common shares without nominal or par value and
10.0 million preferred shares without nominal or par value, issuable in series. Baytex establishes the rights and terms of the
preferred shares upon issuance. As at December 31, 2023, 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 meeting 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, 2021
Vesting of share awards
Common shares repurchased and cancelled
Balance, December 31, 2022
Issued on corporate acquisition (note 4)
Vesting of share awards
Common shares repurchased and cancelled
Balance, December 31, 2023
Number of
Common Shares
(000s)
564,213 $
5,035
(24,318)
544,930 $
311,370
5,892
(40,511)
821,681 $
Amount
5,736,593
8,501
(245,430)
5,499,664
1,326,435
26,229
(325,039)
6,527,289
Normal Course Issuer Bid ("NCIB") Share Repurchases
On June 23, 2023, Baytex announced the acceptance from the Toronto Stock Exchange ("TSX") for renewal of the NCIB under
which Baytex is permitted to purchase for cancellation 68.4 million common shares over the 12-month period commencing June
29, 2023. The number of shares authorized for repurchase represents 10% of the Company's 856.9 million common shares
outstanding as at June 21, 2023.
Purchases are made on the open market at prices prevailing at the time of the transaction. During the year ended December 31,
2023, Baytex repurchased and cancelled 40.5 million common shares at an average price of $5.48 per share for total
consideration of $221.9 million. During 2022, Baytex repurchased and cancelled 24.3 million common shares at an average price
of $6.54 per share for total consideration of $159.0 million. The total consideration paid includes the commissions and fees paid
as part of the transaction and is recorded as a reduction to shareholders' equity. The shares repurchased and cancelled are
accounted for as a reduction in shareholders' capital at historical cost, with any discount paid recorded to contributed surplus and
any premium paid recorded to retained earnings.
Dividends
In November 2023, the Company's Board of Directors declared a quarterly cash dividend of $0.0225 per share which was paid
on January 2, 2024 for shareholders of record as at December 15, 2023. On February 28, 2024, the Company's Board of
Directors declared a quarterly cash dividend of $0.0225 per share to be paid on April 1, 2024 for shareholders on record as at
March 15, 2024.
The following dividends were declared by Baytex during the year ended December 31, 2023:
Record Date
Payable Date
Per Share Amount
Dividend Amount
September 15, 2023
October 2, 2023
December 15, 2023
January 2, 2024
$0.0225
$0.0225
Total dividends declared
$
$
19,138
18,381
37,519
12. SHARE-BASED COMPENSATION PLAN
For the year ended December 31, 2023, the Company recorded total share-based compensation expense of $37.7 million
($29.1 million for the year ended December 31, 2022) which is comprised of $16.2 million of non-cash expense related to awards
assumed in the acquisition of Ranger which were settled with Baytex common shares after closing of the business combination.
Total share-based compensation expense for the year ended December 31, 2023 also includes the $21.5 million related to cash-
settled awards and the associated equity total return swaps ($25.9 million for the year ended December 31, 2022).
The Company's closing share price on December 31, 2023 was $4.38 (December 31, 2022 - $6.08).
84
2023 / Annual Report / Baytex Energy
Share Award Incentive Plan
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 directors, officers and employees of the Company and its
subsidiaries. Pursuant to the Share Award Incentive Plan, Baytex has the option to settle amounts payable related to Share
Awards in cash on the settlement date. 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 exceed 3.8% of the then-issued and outstanding common
shares.
A restricted award entitles the holder of each award to receive one common share of Baytex or the equivalent cash value at the
time of vesting. A performance award entitles the holder of each award to receive between zero and two common shares or the
cash equivalent value on vesting; the number of common shares issued is determined by a performance multiplier. The multiplier
can range between zero and two and is calculated based on a number of factors determined and approved by the Board of
Directors on an annual basis. The multiplier is dependent on the performance of the Company relative to predefined corporate
performance measures for a particular period. The number Share Awards is adjusted to account for the payment of dividends
from the grant date to the applicable issue date. The Share Awards vest in equal tranches on the first, second and third
anniversaries of the grant date. The cumulative expense is recognized at fair value at each period end and is included in share-
based compensation liability.
When Share Awards are accounted for as equity-settled, share-based compensation expense is determined using the fair value
of the Share Awards on the grant date which is based on quoted market prices for the Company's common shares. Share
Awards vest in equal tranches on the first, second and third anniversaries of the grant date and are expensed over the vesting
period using the graded vesting method, with a corresponding increase to contributed surplus. On the vest date, the associated
contributed surplus is recognized in shareholders' capital.
In 2022, the Company received approval from its Board of Directors to settle the existing Share Awards with cash under the
terms of the Share Award Incentive Plan. As a result, Baytex recognized the fair value of the liability for amortized unvested
Share Awards in share-based compensation liability. For the year-ended December 31, 2022, the fair value of the liability
recognized exceeded the amount previously recognized in contributed surplus of $4.8 million and the excess was recognized as
share-based compensation expense in the period.
Liabilities associated with cash-settled awards are determined based on the fair value of the award at grant date and are
subsequently revalued at each period end until the date of settlement. This valuation incorporates the period-end share price, the
number of awards outstanding at each period end, and certain management estimates, such as estimated forfeitures and
performance multiplier, if applicable. Share-based compensation expense related to cash-settled awards is recognized in the
consolidated statements of income (loss) and comprehensive income (loss) over the relevant service period with a
corresponding increase or decrease in share-based compensation liability. Classification of the associated short-term and long-
term liabilities is dependent on the expected payout dates of the individual awards.
On June 20, 2023, Baytex became the successor to Ranger's Share Award Plan (note 4). Although no new grants will be made
under the Ranger Share Award Plan, awards that were outstanding at June 20, 2023 were converted to restricted awards that
will be settled in shares of Baytex or with cash, with the quantity outstanding adjusted based on the exchange ratio for the
business combination with Ranger.
The weighted average fair value of Share Awards granted during the year ended December 31, 2023 was $5.40 per restricted
and performance award ($6.08 for the year ended December 31, 2022).
2023 / Annual Report / Baytex Energy 85
The number of Share Awards outstanding is detailed below:
(000s)
Balance, December 31, 2021
Granted
Vested
Forfeited
Balance, December 31, 2022
Granted
Assumed on corporate acquisition (1)
Vested
Forfeited
Balance, December 31, 2023
Number of
restricted awards
Number of
performance awards
Total number of
Share Awards
2,093
68
(1,377)
(22)
762
41
10,789
(9,302)
(11)
2,279
7,381
1,391
(3,630)
(346)
4,796
2,641
—
(3,767)
(315)
3,355
9,474
1,459
(5,007)
(368)
5,558
2,682
10,789
(13,069)
(326)
5,634
(1) Following the closing of the transaction, holders of awards outstanding under Ranger's Share Award Plan were entitled to Baytex common
shares rather than Ranger common shares with adjustment to the quantity outstanding based on the exchange ratio for Ranger shares. The
fair value of share awards allocated to consideration was based on the service period that had occurred prior to the acquisition date (note 4)
while the remaining fair value of the share awards assumed by Baytex will be recognized over the remaining future service periods.
Incentive Award Plan
Baytex has an Incentive Award Plan whereby the participants of the plan are entitled to receive a cash payment equal to the
value of one Baytex common share per incentive award at the time of vesting. The incentive awards vest in equal tranches on
the first, second and third anniversaries of the grant date using the graded vesting method. The cumulative expense is
recognized at fair value at each period end and is included in share-based compensation liability.
During the year ended December 31, 2023, Baytex granted 2.6 million awards under the Incentive Award Plan at a fair value of
$5.35 per award (1.4 million awards at $5.70 per award for the year ended December 31, 2022). At December 31, 2023 there
were 4.5 million awards outstanding under the Incentive Award Plan (December 31, 2022 - 5.1 million).
Deferred Share Unit Plan ("DSU Plan")
Baytex has a DSU Plan whereby each independent director of Baytex is entitled to receive a cash payment equal to the value of
one Baytex common share per DSU award on the date at which they cease to be a member of the Board. The awards vest
immediately upon being granted and are expensed in full on the grant date. The units are recognized at fair value at each period
end and are included in share-based compensation liability.
During the year ended December 31, 2023, Baytex granted 0.3 million awards under the DSU Plan at a fair value of $5.15 per
award (0.2 million awards at $5.68 per award for the year ended December 31, 2022). At December 31, 2023, there were
1.2 million awards outstanding under the DSU Plan (December 31, 2022 - 1.0 million).
Equity Total Return Swaps
The Company uses equity total return swaps on the equivalent number of Baytex common shares in order to fix a portion of the
aggregate cost of the Company's cash-settled plans including the Incentive Award Plan, the DSU Plan and the Share Award
Incentive Plan, at the fair value determined on the grant date.
At December 31, 2023, an asset of $1.0 million associated with the equity total return swap was included in trade receivables
(December 31, 2022 - $21.2 million).
86
2023 / Annual Report / Baytex Energy
13. NET (LOSS) INCOME 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 were converted to common shares. The treasury stock method is used to determine the
dilutive effect of share awards whereby the potential conversion of share awards and the amount of compensation expense, if
any, attributed to future services are assumed to be used to purchase common shares at the average market price during the
year.
Years Ended December 31
2023
Weighted
average
common
shares
(000's)
Net (loss)
income
Net (loss)
income per
share Net income
2022
Weighted
average
common
shares
(000's)
Net income
per share
Net (loss) income - basic
$
(233,356)
704,896 $
(0.33) $
855,605
557,986 $
Dilutive effect of share awards
—
—
—
—
5,849
Net (loss) income - diluted
$
(233,356)
704,896 $
(0.33) $
855,605
563,835 $
1.53
—
1.52
For the year ended December 31, 2023, all share awards were excluded from the calculation of diluted loss per share as their
effect was anti-dilutive given the Company recorded a loss. For the year ended December 31, 2022, 0.3 million share awards
were excluded from the calculation of diluted income per share as their effect was anti-dilutive.
14. PETROLEUM AND NATURAL GAS SALES
Petroleum and natural gas sales from contracts with customers for the Company's Canadian and U.S. operating segments is set
forth in the following table.
Years Ended December 31
2023
2022
Light oil and condensate
$
574,910 $ 1,454,213 $ 2,029,123 $
693,043 $
777,506 $ 1,470,549
Canada
U.S.
Total
Canada
U.S.
Total
Heavy oil
NGL
Natural gas
1,081,549
—
1,081,549
1,102,076
—
1,102,076
23,174
49,388
122,823
76,564
145,997
125,952
30,847
100,595
89,658
95,320
120,505
195,915
Total petroleum and natural gas sales
$ 1,729,021 $ 1,653,600 $ 3,382,621 $ 1,926,561 $
962,484 $ 2,889,045
Included in trade receivables at December 31, 2023 is $271.1 million of accrued receivables related to delivered volumes
(December 31, 2022 - $180.3 million).
2023 / Annual Report / Baytex Energy 87
15.
INCOME TAXES
The provision for income taxes has been computed as follows:
Net (loss) income before income taxes
Expected income taxes at the statutory rate of 24.64% (2022 – 24.80%) (1)
Increase (decrease) in income taxes resulting from:
$
Effect of foreign exchange
Effect of rate adjustments for foreign jurisdictions
Effect of change in deferred tax benefit not recognized (2)
Effect of internal debt restructuring (3)
Repatriation and related taxes
Adjustments, assessments and other
Income tax (recovery) expense
Years Ended December 31
2023
(516,582) $
(127,286)
(2,089)
5,062
6,347
(186,460)
13,565
7,635
2022
890,915
220,947
4,976
(25,522)
(129,931)
(44,762)
—
9,602
35,310
$
(283,226) $
(1) The expected income tax rate decreased due to changes in the provincial apportionment of Canadian income.
(2) A deferred tax asset of $40.4 million remains unrecognized due to uncertainty surrounding future commodity prices and future capital gains
(December 31, 2022 - $14.4 million). These deferred income tax assets relate to capital losses of $101.8 million and non-capital losses of
$113.0 million.
(3) A deferred income tax asset has been recognized immediately after the closing of the Ranger acquisition due to effects of the transaction
structuring.
In June 2016, certain indirect subsidiary entities received reassessments from the Canada Revenue Agency ("CRA") that deny
non-capital loss deductions relevant to the calculation of income taxes for the years 2011 through 2015. Following objections and
submissions, in November 2023 the CRA issued notices of confirmation regarding their prior reassessments. In February 2024,
Baytex filed notices of appeal with the Tax Court of Canada and we estimate it could take between two and three years to
receive a judgment. The reassessments do not require us to pay any amounts in order to participate in the appeals process.
Should we be unsuccessful at the Tax Court of Canada, additional appeals are available; a process that we estimate could take
another two years and potentially longer.
We remain confident that the tax filings of the affected entities are correct and are vigorously defending our tax filing positions. In
addition, we have purchased $272.5 million of insurance coverage for a premium of $50.3 million to help manage the litigation
risk associated with this matter. The most recent reassessments issued by the CRA assert taxes owing by the trusts (described
below) of $244.8 million, late payment interest of $166.6 million as of the date of the reassessments, and a late filing penalty in
respect of the 2011 tax year of $4.1 million.
By way of background, we acquired several privately held commercial trusts in 2010 with accumulated non-capital losses of
$591.0 million (the "Losses"). The Losses were subsequently deducted in computing the taxable income of those trusts. The
reassessments, as confirmed in November 2023, disallow the deduction of the Losses for two reasons. Firstly, the
reassessments allege that (i) the trusts were resettled, and (ii) the resulting successor trusts were not able to access the losses
of the predecessor trusts. Secondly, the reassessments allege that the general anti-avoidance rule of the Income Tax Act
(Canada) operates to deny the deduction of the losses. If, after exhausting available appeals, the deduction of Losses continues
to be disallowed, either the trusts or their corporate beneficiary will owe cash taxes, late payment interest and potentially
penalties. The amount of cash taxes owing, late payment interest and potential penalties are dependent upon the taxpayer(s)
ultimately liable (the trusts or their corporate beneficiary) and the amount of unused tax shelter available to those/that taxpayer(s)
to offset the reassessed income, including tax shelter from future years that may be carried back and applied to prior years.
For the year-ended December 31, 2023, Baytex forecasts effective tax rates will exceed 15% in all jurisdictions in which we
operate and therefore does not anticipate owing any top-up taxes under Pillar Two legislation.
88
2023 / Annual Report / Baytex Energy
A continuity of the net deferred income tax liability is detailed in the following tables:
As at
Taxable temporary differences:
January 1, 2023
Recognized in
Net Income
Business
Combination
Foreign
Currency
Translation
Adjustment
December 31,
2023
Petroleum and natural gas properties
$
(807,514) $
200,623 $
(111,131) $
11,921 $
(706,101)
Financial derivatives
Other
Deductible temporary differences:
Asset retirement obligations
Non-capital losses (1)(2)
Finance costs
(2,506)
(20,951)
145,275
416,131
60,951
4,506
8,225
(873)
79,343
5,805
(4,738)
—
6,575
156,385
53,761
—
(320)
(121)
(4,298)
(5,237)
(2,738)
(13,046)
150,856
647,561
115,280
Net deferred income tax (liability) asset (3) $
(208,614) $
297,629 $
100,852 $
1,945 $
191,812
(1) Non-capital loss carry-forwards at December 31, 2023 totaled $3.2 billion, of which $2.6 billion will expire from 2033 to 2040, and $575.7
million does not have an expiry date.
(2) A deferred income tax asset of $213.1 million has been recognized in respect of non-capital losses of a wholly owned financing subsidiary
of Baytex; which losses will be offset against future interest income to be earned as a result of an internal debt restructuring.
(3) The net deferred income tax asset is comprised of a deferred income tax asset of $213.1 million and a deferred income tax liability of $21.3
million.
As at
Taxable temporary differences:
January 1, 2022
Recognized in Net
Loss
Foreign Currency
Translation
Adjustment
December 31,
2022
Petroleum and natural gas properties
$
(760,579) $
(18,081) $
(28,854) $
(807,514)
Financial derivatives
Other
Deductible temporary differences:
Asset retirement obligations
Financial derivatives
Non-capital losses (1)
Finance costs
—
(21,616)
185,336
31,492
342,884
55,027
(2,506)
(1,137)
(40,693)
(31,492)
61,005
1,188
—
1,802
632
—
12,242
4,736
(2,506)
(20,951)
145,275
—
416,131
60,951
Net deferred income tax liability
$
(167,456) $
(31,716) $
(9,442) $
(208,614)
(1) Non-capital loss carry-forwards at December 31, 2022 totaled $1.8 billion and will expire from 2033 to 2040.
16. FINANCING AND INTEREST
Interest on Credit Facilities
Interest on long-term notes
Interest on lease obligations
Cash interest
Amortization of debt issue costs
Accretion of asset retirement obligations (note 10)
Early redemption expense
Financing and interest
Years Ended December 31
2023
56,713 $
102,426
684
159,823 $
11,944
20,406
—
2022
19,550
60,643
193
80,386
6,286
15,683
2,462
192,173 $
104,817
$
$
$
2023 / Annual Report / Baytex Energy 89
17. FOREIGN EXCHANGE
Unrealized foreign exchange (gain) loss
Realized foreign exchange loss (gain)
Foreign exchange (gain) loss
Years Ended December 31
$
$
2023
(14,300) $
3,452
(10,848) $
2022
45,073
(1,632)
43,441
18. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
The Company's financial assets and liabilities are comprised of cash, trade receivables, trade payables, financial derivatives,
Credit Facilities and long-term notes. The fair value of cash, trade receivables, trade payables and dividends payable
approximates carrying value due to the short term to maturity. The fair value of the Credit Facilities is equal to the principal
amount outstanding as the Credit Facilities bear interest at floating rates and credit spreads that are indicative of market rates.
The fair value of the long-term notes is determined based on market prices.
The 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, 2023
December 31, 2022
Carrying value
Fair value Carrying value
Fair value
Fair Value
Measurement
Hierarchy
Financial Assets
FVTPL
Financial Derivatives
Total
Amortized cost
Cash
Trade receivables
Total
Financial Liabilities
Amortized cost
Trade payables
Dividends payable
Credit Facilities
Long-term notes
Total
$
$
$
$
23,274 $
23,274 $
23,274 $
23,274 $
10,105 $
10,105 $
10,105
10,105
Level 2
55,815 $
55,815 $
5,464 $
339,405
339,405
222,108
395,220 $
395,220 $
227,572 $
5,464
222,108
227,572
$
(477,295) $
(477,295) $
(227,332) $
(227,332)
(18,381)
(18,381)
(848,749)
(864,736)
(1,562,361)
(1,653,118)
—
(383,031)
(547,598)
—
(385,394)
(563,292)
$
(2,906,786) $
(3,013,530) $
(1,157,961) $
(1,176,018)
—
—
—
—
Level 1
Baytex classifies the fair value of financial instruments according to the following hierarchy based on the number 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.
There were no transfers between Level 1 and Level 2 during the years ended December 31, 2023 or 2022.
90
2023 / Annual Report / Baytex Energy
Foreign Currency Risk
In entities with a Canadian dollar functional currency, Baytex is exposed to fluctuations in foreign exchange rates as a result of
the U.S. dollar portion of its Credit Facilities, long-term notes and crude oil sales based on U.S. dollar benchmark prices. The
Company's net income or loss, comprehensive income or loss and cash flow will therefore be impacted by fluctuations in foreign
exchange rates.
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 $12.3 million.
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$17,923
US$6,980
US$1,249,725
US$430,171
Assets
Liabilities
December 31, 2023
December 31, 2022
December 31, 2023
December 31, 2022
Interest Rate Risk
The Company's interest rate risk arises from borrowing at floating rates under the Credit Facilities (note 8). Based on the
principal outstanding on the Credit Facilities as at December 31, 2023, a 100 basis points change in interest rates would impact
net income or loss before income taxes by approximately $8.6 million for an annual period.
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.
The reported value of commodity financial derivatives is sensitive to changes in forecasted commodity prices. For crude oil
contracts outstanding as at December 31, 2023, a US$1.00/bbl change in the underlying benchmark crude oil prices would
impact net income before income taxes by approximately $13.4 million. For natural gas and natural gas liquids contracts
outstanding as at December 31, 2023, a US$0.25 change in the underlying benchmark natural gas or natural gas liquids prices
would impact net income or loss before income taxes by approximately $4.7 million.
2023 / Annual Report / Baytex Energy 91
Financial Derivative Contracts
Baytex had the following commodity financial derivative contracts outstanding as at February 28, 2024.
Period
Volume
Price/Unit (1)
Oil
Basis differential
Jan 2024 to Jun 2024
4,000 bbl/d
Basis differential
July 2024 to Dec 2024
4,000 bbl/d
Basis differential (2)
July 2024 to Dec 2024
5,000 bbl/d
Basis differential (2)
Apr 2024 to Dec 2024
3,000 bbl/d
Baytex pays: WCS differential at Hardisty
Baytex receives: WCS differential at
Houston less US$8.10/bbl
Baytex pays: WCS differential at Hardisty
Baytex receives: WCS differential at
Houston less US$8.40/bbl
Baytex pays: WCS differential at Hardisty
Baytex receives: WCS differential at
Houston less US$8.18/bbl
Baytex pays: WCS differential at Hardisty
Baytex receives: WCS differential at
Houston less US$8.27/bbl
Basis differential (2)
Basis differential
Basis differential (2)
Basis differential (2)
Collar
Collar
Collar
Collar
Collar
Collar
Collar
Collar
Collar (2)
Collar (2)
Natural Gas
Fixed Sell
Collar
Collar
Collar
Collar
Collar
Collar
Collar
July 2024 to Dec 2024
3,000 bbl/d
WTI less US$13.70/bbl
Jan 2024 to Dec 2024
1,500 bbl/d
WTI less US$2.65/bbl
Apr 2024 to Dec 2024
1,250 bbl/d
WTI less US$3.40/bbl
July 2024 to Dec 2024
2,500 bbl/d
WTI less US$2.85/bbl
Jan 2024 to Mar 2024
10,400 bbl/d
US$60.00/US$100.00
Jan 2024 to Jun 2024
24,500 bbl/d
US$60.00/US$100.00
July 2024 to Dec 2024
2,500 bbl/d
US$60.00/US$90.21
Apr 2024 to Jun 2024
11,750 bbl/d
US$60.00/US$100.00
July 2024 to Dec 2024
2,500 bbl/d
US$60.00/US$94.15
July 2024 to Dec 2024
10,000 bbl/d
US$60.00/US$100.00
July 2024 to Sep 2024
10,000 bbl/d
US$60.00/US$100.00
Oct 2024 to Dec 2024
2,500 bbl/d
US$60.00/US$100.00
July 2024 to Dec 2024
9,000 bbl/d
US$60.00/US$84.58
Oct 2024 to Dec 2024
7,000 bbl/d
US$60.00/US$86.43
Jan 2024 to Mar 2024
3,500 mmbtu/d US$3.5025
Jan 2024 to Mar 2024
11,538 mmbtu/d US$2.50/US$3.65
Apr 2024 to Jun 2024
11,538 mmbtu/d US$2.33/US$3.00
Jan 2024 to Dec 2024
2,500 mmbtu/d US$3.00/US$4.06
Jan 2024 to Dec 2024
2,500 mmbtu/d US$3.00/US$4.09
Jan 2024 to Dec 2024
5,000 mmbtu/d US$3.00/US$4.10
Jan 2024 to Dec 2024
8,500 mmbtu/d US$3.00/US$4.15
Jan 2024 to Dec 2024
5,000 mmbtu/d US$3.00/US$4.19
Index
WCS
WCS
WCS
WCS
WCS
MSW
MSW
MSW
WTI
WTI
WTI
WTI
WTI
WTI
WTI
WTI
WTI
WTI
NYMEX
NYMEX
NYMEX
NYMEX
NYMEX
NYMEX
NYMEX
NYMEX
Natural Gas Liquids
Fixed Sell
Jan 2024 to Mar 2024
34,364 gallon/d US$0.2280/gallon
Mt. Belvieu Non-
TET Ethane
(1) Based on the weighted average price per unit for the period.
(2) Contracts entered subsequent to December 31, 2023.
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 (gain) loss
92
2023 / Annual Report / Baytex Energy
Years Ended December 31
2023
(36,212) $
11,517
(24,695) $
2022
334,481
(135,471)
199,010
$
$
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 management of forecasted and actual
cash flows from operating, financing and investing activities, available capacity under existing credit facility arrangements, and
opportunities to issue additional common shares.
The timing of cash outflows relating to financial liabilities as at December 31, 2023 is outlined in the table below:
Total
2024
2025-2026
2027-2028
Trade payables
$
477,295 $
477,295 $
— $
Credit Facilities - principal
Long-term notes - principal (1)
Interest on long-term notes (2)
864,736
1,597,475
722,732
—
—
864,736
—
137,138
274,276
2029 and
beyond
—
—
— $
—
541,114
191,515
1,056,361
119,803
(1) The US$409.8 million principal amount of 8.75% senior unsecured notes is due April 1, 2027 and the US$800.0 million principal amount of
8.50% senior unsecured notes is due April 30, 2030.
(2) Excludes interest on Credit Facilities as interest payments on Credit Facilities fluctuate based on amounts outstanding and the prevailing
$
3,662,238 $
614,433 $
1,139,012 $
732,629 $
1,176,164
interest rate at the time of borrowing.
Credit Risk
Credit risk is the risk that a counterparty to a financial asset will default resulting in Baytex incurring a loss. As at December 31,
2023, the Company is exposed to credit risk with respect to its cash, trade receivables and financial derivatives. Baytex manages
these risks through the selection and monitoring of credit-worthy counterparties.
Most of the Company's trade receivables relate to petroleum and natural gas sales. Baytex reviews its exposure to individual
entities on a regular basis and manages its credit risk by entering into sales contracts after reviewing the creditworthiness of the
entity. Letters of credit or parental guarantees may be obtained prior to the commencement of business with certain
counterparties. Credit risk may also arise from financial derivative instruments. 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. The maximum exposure to credit risk is equal to the carrying value of the financial assets. The Company
considers all financial assets that are not impaired or past due to be of good credit quality.
The majority of the Company's credit exposure on trade receivables at December 31, 2023 relates to accrued revenues.
Accounts receivable from purchasers of the Company's petroleum and natural gas sales are typically collected on the 25th day
of the month following production. Joint interest receivables are typically collected within one to three months following
production.
Should the Company determine that the ultimate collection of a receivable is in doubt, the carrying amount of trade receivables is
reduced by adjusting the allowance for doubtful accounts and recording 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, 2023, allowance for doubtful accounts was $1.5 million (December 31, 2022 -
$2.5 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. Baytex has estimated the lifetime expected credit loss as at
and for the year ended December 31, 2023 to be nominal.
The Company's trade receivables, net of the allowance for doubtful accounts, were aged as follows at December 31, 2023.
Trade Receivables Aging
Current (less than 30 days)
31-60 days
61-90 days
Past due (more than 90 days)
December 31, 2023
December 31, 2022
321,450 $
216,345
14,836
461
2,658
1,993
766
3,005
339,405 $
222,108
$
$
2023 / Annual Report / Baytex Energy 93
19. SUPPLEMENTAL INFORMATION
Changes in Non-Cash Working Capital Items
Trade receivables
Prepaids and other assets
Trade payables
Share-based compensation liability
Dividends payable
Non-cash working capital acquired (note 4)
Changes in non-cash working capital related to:
Operating activities
Financing activities
Investing activities
Transfers from equity
Foreign currency translation on non-cash working capital
Income Statement Presentation
Years Ended December 31
$
$
$
$
2023
(117,297) $
(76,882)
236,560
(18,340)
18,381
(230,012)
(187,590) $
(220,895) $
(3,068)
46,810
—
(10,437)
(187,590) $
2022
(54,963)
(113)
42,337
48,375
—
—
35,636
26,072
—
9,401
4,791
(4,628)
35,636
Baytex's consolidated statements of income (loss) and comprehensive income (loss) are prepared according to the nature of
expense, with the exception of employee compensation costs which are included in both operating expense and general and
administrative expense line items.
The following table details the amount of total employee compensation costs included in the operating expense and general and
administrative expense.
Operating
General and administrative
Total employee compensation costs
20. COMMITMENTS
Years Ended December 31
2023
17,975 $
49,633
67,608 $
2022
11,814
35,935
47,749
$
$
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 (note 22). These obligations as of December 31, 2023 and the expected timing
of funding of these obligations, are noted in the table below.
Processing agreements
Transportation agreements
Total
Total
5,642 $
2024
2025-2026
2027-2028
618 $
1,003 $
563 $
212,400
52,691
94,866
47,601
218,042 $
53,309 $
95,869 $
48,164 $
$
$
2029 and
beyond
3,458
17,242
20,700
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 (note 10). The present value of the future estimated abandonment and reclamation costs are
included in the asset retirement obligations presented in the statement of financial position. Programs to abandon and reclaim
wellsites and facilities are undertaken regularly in accordance with applicable legislative requirements.
94
2023 / Annual Report / Baytex Energy
21. RELATED PARTIES
Transactions with key management personnel and directors are noted in the table below.
Short-term employee benefits
Share-based compensation
Termination payments
Total compensation for key management personnel
22. CAPITAL MANAGEMENT
Years Ended December 31
2023
7,753 $
9,924
—
17,677 $
2022
6,868
9,043
1,758
17,669
$
$
The Company's capital management objective is to maintain a strong balance sheet that provides financial flexibility to execute
its development programs, provide returns to shareholders and optimize its portfolio through strategic acquisitions. Baytex strives
to actively manage its capital structure in response to changes in economic conditions. At December 31, 2023, the Company's
capital structure was comprised of shareholders' capital, long-term notes, trade receivables, prepaids and other assets, trade
payables, share-based compensation liability, dividends payable, cash and the Credit Facilities.
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.
The capital-intensive nature of Baytex's operations requires the maintenance of adequate sources of liquidity to fund ongoing
exploration and development. Baytex's capital resources consist primarily of adjusted funds flow, available Credit Facilities and
proceeds received from the divestiture of oil and gas properties. The following capital management measures and ratios are
used to monitor current and projected sources of liquidity.
Net Debt
The Company uses net debt to monitor its current financial position and to evaluate existing sources of liquidity. The Company
defines net debt to be the sum of our Credit Facilities and long-term notes outstanding adjusted for unamortized debt issuance
costs, trade payables, dividends payable, share-based compensation liability, other long-term liabilities, cash, trade receivables
and prepaids and other assets. Baytex also uses net debt projections to estimate future liquidity and whether additional sources
of capital are required to fund ongoing operations.
The following table reconciles net debt to amounts disclosed in the primary financial statements.
December 31, 2023
December 31, 2022
Credit Facilities
$
848,749 $
Unamortized debt issuance costs - Credit Facilities (note 8)
Long-term notes
Unamortized debt issuance costs - Long-term notes (note 9)
Trade payables
Dividends payable
Share-based compensation liability
Other long-term liabilities
Cash
Trade receivables
Prepaids and other assets
Net Debt
15,987
1,562,361
35,114
477,295
18,381
35,732
19,147
(55,815)
(339,405)
(83,259)
$
2,534,287 $
383,031
2,363
547,598
6,999
227,332
—
54,072
—
(5,464)
(222,108)
(6,377)
987,446
2023 / Annual Report / Baytex Energy
59
Adjusted Funds Flow
Adjusted funds flow is used to monitor operating performance and the Company's ability to generate funds for exploration and
development expenditures and settlement of abandonment obligations. Adjusted funds flow is comprised of cash flows from
operating activities adjusted for changes in non-cash working capital, asset retirements obligations settled during the applicable
period, transaction costs and cash premiums on derivatives.
Adjusted funds flow is reconciled to amounts disclosed in the primary financial statements in the following table.
Cash flows from operating activities
Change in non-cash working capital
Asset retirement obligations settled
Transaction costs
Cash premiums on derivatives
Adjusted Funds Flow
Years Ended December 31
2023
$
1,295,731 $
220,895
26,416
49,045
2,263
2022
1,172,872
(26,072)
18,351
—
—
$
1,594,350 $
1,165,151
69
2023 / Annual Report / Baytex Energy
ABBREVIATIONS
AECO
bbl
bbl/d
boe*
boe/d
COSO
GAAP
GJ
GJ/d
IAS
IASB
the natural gas storage facility located
at Suffield, Alberta
barrel
barrel per day
barrels of oil equivalent
barrels of oil equivalent per day
Committee of Sponsoring
Organizations of the Treadway
Commission
generally accepted accounting
principles
gigajoule
gigajoule per day
International Accounting Standard
International Accounting Standards
Board
IFRS
LLS
mbbl
mboe*
mcf
mcf/d
mmBtu
mmBtu/d
mmcf
mmcf/d
NGL
NYMEX
NYSE
TSX
WCS
WTI
International Financial Reporting
Standards
Louisiana Light Sweet
thousand barrels
thousand barrels of oil equivalent
thousand cubic feet
thousand cubic feet per day
million British Thermal Units
million British Thermal Units per day
million cubic feet
million cubic feet per day
natural gas liquids
New York Mercantile Exchange
New York Stock Exchange
Toronto Stock Exchange
Western Canadian Select
West Texas Intermediate
*
Oil equivalent amounts may be misleading, particularly if used in isolation. In accordance with NI 51-101, a boe conversion
ratio for natural gas of 6 Mcf: 1 bbl has been used, which is based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value equivalency at the wellhead.
Baytex Energy Corp. 2023 Annual Report 97
CORPORATE
INFORMATION
BOARD OF DIRECTORS
Mark R. Bly
Chairman of the Board
Eric T. Greager
Director
Tiffany (TJ) Thom Cepak 1,3
Director
Trudy M. Curran 2,4
Director
Don G. Hrap 1,3
Director
Angela S. Lekatsas 1,4
Director
Jennifer A. Maki 1,2
Director
David L. Pearce 2,3
Director
Steve D.L. Reynish 3,4
Director
Jeffrey E. Wojahn 2,4
Director
(1) Member of the Audit Committee
(2) Member of the Human Resources
and Compensation Committee
(3) Member of the Reserves
and Sustainability Committee
(4) Member of the Nominating
and Governance Committee
HEAD OFFICE
Baytex Energy Corp.
Centennial Place, East Tower
2800, 520 - 3rd Avenue SW
Calgary, Alberta T2P 0R3
Toll-free 1.800.524.5521
T 587.952.3000
F 587.952.3001
BAYTEXENERGY.COM
Design: ARTHUR / HUNTER
Printing: Merrill Corporation
OFFICERS
Eric T. Greager
President and
Chief Executive Officer
Chad L. Kalmakoff
Chief Financial Officer
Chad E. Lundberg
Chief Operating Officer
James R. Maclean
Chief Legal Officer and
Corporate Secretary
Brian G. Ector
Senior Vice President,
Capital Markets and Investor Relations
Kendall D. Arthur
Senior Vice President and
General Manager, Canadian
Heavy Oil Operations
Julia C. Gwaltney
Senior Vice President and
General Manager, U.S. Eagle
Ford Operations
Nicole M. Frechette
Vice President and General Manager,
Canadian Light Oil Operations
Chris M.P. Lessoway
Vice President,
Finance and Treasurer
AUDITORS
KPMG LLP
RESERVES ENGINEERS
McDaniel & Associates
Consultants Ltd.
TRANSFER AGENT
Odyssey Trust Company
EXCHANGE LISTINGS
New York Stock Exchange
Toronto Stock Exchange
Symbol: BTE
M
O
Y.C
G
R
E
N
E
X
E
T
Y
A
W.B
W
W