UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 6-K
Report of Foreign Private Issuer
Pursuant to Rule 13a-16 or 15d-16 Under
the
Securities Exchange Act
of 1934
For the month of August 2023
Commission File Number: 1-32754
BAYTEX ENERGY CORP.
(Exact name of registrant as specified in its charter)
2800, 520 – 3rd AVENUE S.W.
CALGARY, ALBERTA, CANADA
T2P 0R3
(Address of principal executive office)
Indicate by check mark whether the registrant files or will file annual
reports under cover Form 20-F or Form 40-F.
Indicate by check mark if the registrant is submitting the Form 6-K
in paper as permitted by Regulation S-T Rule 101(b)(1): ¨
Indicate by check mark if the registrant is submitting the Form 6-K
in paper as permitted by Regulation S-T Rule 101(b)(7): ¨
Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the
information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.
If “Yes” is marked, indicate below the file number assigned
to the registrant in connection with Rule 12g3-2(b):
The following document attached as an exhibit hereto is incorporated
by reference herein:
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| BAYTEX ENERGY CORP. |
| | |
| /s/ James R. Maclean |
| Name: | James R. Maclean |
| Title: | Chief Legal Officer and Corporate
Secretary |
Dated: August 1, 2023
Exhibit 99.1
BAYTEX ANNOUNCES SECOND QUARTER 2023 RESULTS
CALGARY, ALBERTA (July 27, 2023)
- Baytex Energy Corp. ("Baytex") (TSX:BTE) (NYSE:BTE) reports its operating and financial results for the three and six months
ended June 30, 2023 (all amounts are in Canadian dollars unless otherwise noted).
“We continue to execute on our
base business, and following the Ranger transaction, have emerged as a well-capitalized and diversified North American exploration and
production company. We have a strong portfolio of high-quality oil weighted assets in Western Canada and the Eagle Ford shale in Texas
and we are poised to deliver a powerful combination of free cash flow and increased shareholder returns on a per-share basis. We have
initiated our share buyback program (repurchased 4.7 million shares to-date in July) and declared a quarterly dividend of $0.0225 per
share ($0.09 per share annualized). We are committed to operational excellence and delivering long-term value and enhanced shareholder
returns," commented Eric T. Greager, President and Chief Executive Officer.
Highlights
| · | Completed the acquisition of Ranger Oil Corporation ("Ranger") on June 20, 2023. |
| · | Generated production of 89,761 boe/d (86% oil and NGLs) in Q2/2023. |
| · | Reported cash flows from operating activities of $192 million ($0.33 per basic share) in Q2/2023. |
| · | Delivered adjusted funds flow(1) of $274 million ($0.47 per basic share) in Q2/2023. |
| · | Generated free cash flow(2) of $96 million ($0.17 per basic share) in Q2/2023. |
| · | Exploration and development expenditures totaled $171 million in Q2/2023, consistent with our full-year
plan. |
| · | Completed six-well Duvernay program with wells onstream in Q3/2023. |
| · | New heavy oil exploration success in Waseca near Cold Lake, Alberta. |
On June 20, 2023, we closed the
acquisition of Ranger, adding quality scale in the Eagle Ford and reinforcing a resilient and sustainable business. The total consideration
paid by Baytex, including assumption of net debt(1), was US$2.4 billion (C$3.2 billion). 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. Our second quarter results include
11 days of operations from Ranger.
In conjunction with closing of the
acquisition, we increased our direct shareholder returns to 50% of free cash flow(2) which will allow us to increase the
value of our share buyback program and introduce a dividend. The remainder of our free cash flow continues to be allocated to debt reduction.
On June 23, 2023, we renewed our
Normal Course Issuer Bid with the Toronto Stock Exchange for a share buyback program for up to 10% of our public float. Through July 26,
2023, we have repurchased 4.7 million common shares at an average price of $4.59 per share.
The Board of Directors has declared
a quarterly cash dividend of $0.0225 per share to be paid on October 2, 2023 for shareholders of record on September 15, 2023(3)
(1) | Capital management measure. Refer to the Specified Financial Measures 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) | Refer to the dividend advisory section in this press release for further information. |
2023 Outlook
Following the Ranger transaction, Baytex has emerged
as a well-capitalized, diversified oil-weighted North American E&P company with a strong free cash flow profile. Based on the forward
strip(1), we expect to generate over $400 million of free cash flow(2) in the second half of 2023, and approximately
$500 million of free cash flow for the full-year 2023.
For 2023, we continue to forecast exploration
and development expenditures of $1,005 to $1,045 million, which are expected to generate an average production rate of 120,500 to 122,500
boe/d. For the second half of 2023, we expect production to average 153,000 to 157,000 boe/d. Our production mix for the second half of
2023 is forecast to be 84% oil and NGLs (50% light oil, 22% heavy oil and 12% NGLs) and 16% natural gas.
The following table summarizes our 2023 guidance for production and
exploration and development expenditures.
| |
H1/2023 Actual | | |
H2/2023 Guidance | | |
2023 Guidance | |
Production (boe/d) | |
| 88,269 | (3) | |
| 153,000-157,000 | | |
| 120,500-122,500 | |
Exploration and development expenditures ($ millions) | |
$ | 404 | | |
| $601-$641 | | |
| $1,005-$1,045 | |
We have updated our full-year 2023 cost assumptions
to reflect the Ranger acquisition. Guidance for unit operating expenses decreased by 13% to reflect the lower cost structure of the Ranger
asset base, while unit general and administrative expenses increased by 10% to reflect costs associated with Ranger personnel, and interest
expense is higher due to the incremental debt associated with the Ranger acquisition as well as higher interest rates on the credit facility
due to the rising interest rate environment.
The following table summarizes our 2023 guidance for expenses, leasing
expenditures and asset retirement obligations.
| |
| 2023 Original Guidance (4) | | |
| 2023 Revised Guidance (5) | |
Expenses: | |
| | | |
| | |
Average royalty rate (2) | |
| 20.0 - 22.0% | | |
| 21.0 - 22.0% | |
Operating (6) | |
| $14.00 - $14.75/boe | | |
| $12.25 - $12.75/boe | |
Transportation (6) | |
| $1.90 - $2.10/boe | | |
| $2.00 - $2.10/boe | |
General and administrative (6) | |
| $52 million ($1.63/boe) | | |
| $80 million ($1.80/boe) | |
Interest (6) | |
| $65 million ($2.04/boe) | | |
| $150 million ($3.38/boe) | |
| |
| | | |
| | |
Leasing expenditures | |
| $4 million | | |
| $13 million | |
Asset retirement obligations | |
| $25 million | | |
| $25 million | |
| (1) | H2/2023 commodity prices: WTI - US$75/bbl, WCS differential to WTI - US$14/bbl, NYMEX Gas - US$2.85/MMbtu;
Exchange Rate (CAD/USD) - 1.32. |
| (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) | H1/2023 actual production is comprised of 33,510 bbl/d of light crude oil and medium crude oil (including
condensate), 33,502 bbl/d of heavy crude oil, 7,920 bbl/d of natural gas liquids and 80,017 mcf/d of conventional natural gas. |
| (4) | As announced on December 7, 2022. |
| (5) | Includes Ranger from the closing date of the transaction (June 20, 2023). |
| (6) | Calculated as operating, transportation, general and administrative or cash interest expense divided by
barrels of oil equivalent production volume for the applicable period. |
2 | Baytex Energy Corp. Second Quarter Report 2023 | |
| |
Three Months Ended | | |
Six Months Ended | |
| |
June 30, | | |
March 31, | | |
June 30, | | |
June 30, | | |
June 30, | |
| |
2023 | | |
2023 | | |
2022 | | |
2023 | | |
2022 | |
FINANCIAL | |
| | | |
| | | |
| | | |
| | | |
| | |
(thousands of Canadian dollars, except per common share amounts) | |
| | | |
| | | |
| | | |
| | | |
| | |
Petroleum and natural gas sales | |
$ | 598,760 | | |
$ | 555,336 | | |
$ | 854,169 | | |
$ | 1,154,096 | | |
$ | 1,527,994 | |
Adjusted funds flow (1) | |
| 273,590 | | |
| 236,989 | | |
| 345,704 | | |
| 510,579 | | |
| 625,311 | |
Per share – basic | |
| 0.47 | | |
| 0.43 | | |
| 0.61 | | |
| 0.90 | | |
| 1.10 | |
Per share – diluted | |
| 0.47 | | |
| 0.43 | | |
| 0.60 | | |
| 0.90 | | |
| 1.10 | |
Free cash flow (2) | |
| 96,313 | | |
| (1,918 | ) | |
| 245,316 | | |
| 94,395 | | |
| 366,634 | |
Per share – basic | |
| 0.17 | | |
| — | | |
| 0.43 | | |
| 0.17 | | |
| 0.65 | |
Per share – diluted | |
| 0.16 | | |
| — | | |
| 0.43 | | |
| 0.17 | | |
| 0.64 | |
Cash flows from operating activities | |
| 192,308 | | |
| 184,938 | | |
| 360,034 | | |
| 377,246 | | |
| 559,008 | |
Per share – basic | |
| 0.33 | | |
| 0.34 | | |
| 0.63 | | |
| 0.67 | | |
| 0.99 | |
Per share – diluted | |
| 0.33 | | |
| 0.34 | | |
| 0.63 | | |
| 0.66 | | |
| 0.98 | |
Net income | |
| 213,603 | | |
| 51,441 | | |
| 180,972 | | |
| 265,044 | | |
| 237,830 | |
Per share – basic | |
| 0.37 | | |
| 0.09 | | |
| 0.32 | | |
| 0.47 | | |
| 0.42 | |
Per share – diluted | |
| 0.36 | | |
| 0.09 | | |
| 0.32 | | |
| 0.47 | | |
| 0.42 | |
| |
| | | |
| | | |
| | | |
| | | |
| | |
Capital Expenditures | |
| | | |
| | | |
| | | |
| | | |
| | |
Exploration and development expenditures | |
$ | 170,704 | | |
$ | 233,626 | | |
$ | 96,633 | | |
$ | 404,330 | | |
$ | 250,455 | |
Acquisitions and divestitures | |
| (112 | ) | |
| 271 | | |
| 194 | | |
| 159 | | |
| 226 | |
Total oil and natural gas capital expenditures | |
$ | 170,592 | | |
$ | 233,897 | | |
$ | 96,827 | | |
$ | 404,489 | | |
$ | 250,681 | |
| |
| | | |
| | | |
| | | |
| | | |
| | |
Net Debt | |
| | | |
| | | |
| | | |
| | | |
| | |
Credit facilities | |
$ | 986,903 | | |
$ | 409,653 | | |
$ | 496,917 | | |
$ | 986,903 | | |
$ | 496,917 | |
Long-term notes | |
| 1,601,468 | | |
| 554,351 | | |
| 643,600 | | |
| 1,601,468 | | |
| 643,600 | |
Long-term debt | |
| 2,588,371 | | |
| 964,004 | | |
| 1,140,517 | | |
| 2,588,371 | | |
| 1,140,517 | |
Working capital | |
| 226,473 | | |
| 31,166 | | |
| (17,220 | ) | |
| 226,473 | | |
| (17,220 | ) |
Net debt (1) | |
$ | 2,814,844 | | |
$ | 995,170 | | |
$ | 1,123,297 | | |
$ | 2,814,844 | | |
$ | 1,123,297 | |
| |
| | | |
| | | |
| | | |
| | | |
| | |
Shares Outstanding - basic (thousands) | |
| | | |
| | | |
| | | |
| | | |
| | |
Weighted average | |
| 583,365 | | |
| 545,062 | | |
| 566,997 | | |
| 564,319 | | |
| 566,262 | |
End of period | |
| 862,192 | | |
| 545,553 | | |
| 560,139 | | |
| 862,192 | | |
| 560,139 | |
| |
| | | |
| | | |
| | | |
| | | |
| | |
BENCHMARK PRICES | |
| | | |
| | | |
| | | |
| | | |
| | |
Crude oil | |
| | | |
| | | |
| | | |
| | | |
| | |
WTI (US$/bbl) | |
$ | 73.78 | | |
$ | 76.13 | | |
$ | 108.41 | | |
$ | 74.96 | | |
$ | 101.35 | |
MEH oil (US$/bbl) | |
| 75.01 | | |
| 77.42 | | |
| 112.41 | | |
| 76.22 | | |
| 104.56 | |
MEH oil differential to WTI (US$/bbl) | |
| 1.23 | | |
| 1.29 | | |
| 4.00 | | |
| 1.26 | | |
| 3.21 | |
Edmonton par ($/bbl) | |
| 95.13 | | |
| 99.04 | | |
| 137.79 | | |
| 97.09 | | |
| 126.72 | |
Edmonton par differential to WTI (US$/bbl) | |
| (2.95 | ) | |
| (2.88 | ) | |
| (0.47 | ) | |
| (2.91 | ) | |
| (1.68 | ) |
WCS heavy oil ($/bbl) | |
| 78.85 | | |
| 69.44 | | |
| 122.05 | | |
| 74.16 | | |
| 111.48 | |
WCS differential to WTI (US$/bbl) | |
| (15.07 | ) | |
| (24.77 | ) | |
| (12.80 | ) | |
| (19.92 | ) | |
| (13.67 | ) |
Natural gas | |
| | | |
| | | |
| | | |
| | | |
| | |
NYMEX (US$/mmbtu) | |
$ | 2.10 | | |
$ | 3.42 | | |
$ | 7.17 | | |
$ | 2.76 | | |
$ | 6.06 | |
AECO ($/mcf) | |
| 2.35 | | |
| 4.34 | | |
| 6.27 | | |
| 3.34 | | |
| 5.43 | |
| |
| | | |
| | | |
| | | |
| | | |
| | |
CAD/USD average exchange rate | |
| 1.3431 | | |
| 1.3520 | | |
| 1.2766 | | |
| 1.3475 | | |
| 1.2714 | |
| Baytex Energy Corp. Second Quarter Report 2023 | 3 |
| |
Three Months Ended | | |
Six Months Ended | |
| |
June 30, | | |
March 31, | | |
June 30, | | |
June 30, | | |
June 30, | |
| |
2023 | | |
2023 | | |
2022 | | |
2023 | | |
2022 | |
OPERATING | |
| | | |
| | | |
| | | |
| | | |
| | |
Daily Production | |
| | | |
| | | |
| | | |
| | | |
| | |
Light oil and condensate (bbl/d) | |
| 35,322 | | |
| 31,678 | | |
| 33,007 | | |
| 33,510 | | |
| 33,533 | |
Heavy oil (bbl/d) | |
| 32,821 | | |
| 34,191 | | |
| 28,586 | | |
| 33,502 | | |
| 26,921 | |
NGL (bbl/d) | |
| 8,620 | | |
| 7,213 | | |
| 7,468 | | |
| 7,920 | | |
| 7,552 | |
Total liquids (bbl/d) | |
| 76,763 | | |
| 73,082 | | |
| 69,061 | | |
| 74,932 | | |
| 68,006 | |
Natural gas (mcf/d) | |
| 77,989 | | |
| 82,066 | | |
| 84,169 | | |
| 80,017 | | |
| 83,873 | |
Oil equivalent (boe/d @ 6:1) (3) | |
| 89,761 | | |
| 86,760 | | |
| 83,090 | | |
| 88,269 | | |
| 81,985 | |
| |
| | | |
| | | |
| | | |
| | | |
| | |
Netback (thousands of Canadian dollars) | |
| | | |
| | | |
| | | |
| | | |
| | |
Total sales, net of blending and other expense (2) | |
$ | 545,765 | | |
$ | 495,655 | | |
$ | 797,274 | | |
$ | 1,041,420 | | |
$ | 1,429,659 | |
Royalties | |
| (107,920 | ) | |
| (93,253 | ) | |
| (171,559 | ) | |
| (201,173 | ) | |
| (294,279 | ) |
Operating expense | |
| (119,438 | ) | |
| (112,408 | ) | |
| (107,426 | ) | |
| (231,846 | ) | |
| (208,192 | ) |
Transportation expense | |
| (14,574 | ) | |
| (17,005 | ) | |
| (11,758 | ) | |
| (31,579 | ) | |
| (20,973 | ) |
Operating netback (2) | |
$ | 303,833 | | |
$ | 272,989 | | |
$ | 506,531 | | |
$ | 576,822 | | |
$ | 906,215 | |
General and administrative | |
| (15,240 | ) | |
| (11,734 | ) | |
| (11,640 | ) | |
| (26,974 | ) | |
| (23,322 | ) |
Cash financing and interest | |
| (28,255 | ) | |
| (18,375 | ) | |
| (20,474 | ) | |
| (46,630 | ) | |
| (40,901 | ) |
Realized financial derivatives gain (loss) | |
| 16,365 | | |
| 5,415 | | |
| (124,042 | ) | |
| 21,780 | | |
| (208,408 | ) |
Other (4) | |
| (3,113 | ) | |
| (11,306 | ) | |
| (4,671 | ) | |
| (14,419 | ) | |
| (8,273 | ) |
Adjusted funds flow (1) | |
$ | 273,590 | | |
$ | 236,989 | | |
$ | 345,704 | | |
$ | 510,579 | | |
$ | 625,311 | |
| |
| | | |
| | | |
| | | |
| | | |
| | |
Netback (per boe) (5) | |
| | | |
| | | |
| | | |
| | | |
| | |
Total sales, net of blending and other expense (2) | |
$ | 66.82 | | |
$ | 63.48 | | |
$ | 105.44 | | |
$ | 65.18 | | |
$ | 96.34 | |
Royalties | |
| (13.21 | ) | |
| (11.94 | ) | |
| (22.69 | ) | |
| (12.59 | ) | |
| (19.83 | ) |
Operating expense | |
| (14.62 | ) | |
| (14.40 | ) | |
| (14.21 | ) | |
| (14.51 | ) | |
| (14.03 | ) |
Transportation expense | |
| (1.78 | ) | |
| (2.18 | ) | |
| (1.56 | ) | |
| (1.98 | ) | |
| (1.41 | ) |
Operating netback (2) | |
$ | 37.21 | | |
$ | 34.96 | | |
$ | 66.98 | | |
$ | 36.10 | | |
$ | 61.07 | |
General and administrative | |
| (1.87 | ) | |
| (1.50 | ) | |
| (1.54 | ) | |
| (1.69 | ) | |
| (1.57 | ) |
Cash financing and interest | |
| (3.46 | ) | |
| (2.35 | ) | |
| (2.71 | ) | |
| (2.92 | ) | |
| (2.76 | ) |
Realized financial derivatives gain (loss) | |
| 2.00 | | |
| 0.69 | | |
| (16.41 | ) | |
| 1.36 | | |
| (14.04 | ) |
Other (4) | |
| (0.39 | ) | |
| (1.45 | ) | |
| (0.60 | ) | |
| (0.89 | ) | |
| (0.56 | ) |
Adjusted funds flow (1) | |
$ | 33.49 | | |
$ | 30.35 | | |
$ | 45.72 | | |
$ | 31.96 | | |
$ | 42.14 | |
Notes:
(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) | Barrel of oil equivalent ("boe") amounts have been calculated using a conversion rate of six thousand cubic feet of natural
gas to one barrel of oil. The use of boe amounts may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand
cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner
tip and does not represent a value equivalency at the wellhead. |
(4) | Other is comprised of realized foreign exchange gain or loss, other income or expense, current income
tax expense or recovery and cash share-based compensation. Refer to the Q2/2023 MD&A for further information on these amounts. |
(5) | Calculated as royalties, operating, transportation, general and administrative, cash financing and interest
expense or realized financial derivatives loss divided by barrels of oil equivalent production volume for the applicable period. |
4 | Baytex Energy Corp. Second Quarter Report 2023 | |
Q2/2023 Results
We continue to execute on our base business. Production
In Q2/2023 was 89,761 boe/d (86% oil and NGLs), which includes production from Ranger for the 11 days following closing of the acquisition.
Production exceeded the high end of our Q2/2023 guidance range of 88,500 to 89,000 boe/d due to the timing of operated Eagle Ford wells
brought onstream late in the second quarter.
Production in Q2/2023 was reduced by approximately
4,500 boe/d due to the temporary curtailment of production caused by wildfires in Alberta. For the month of July, we expect production
to be curtailed by approximately 2,000 boe/d. Wildfires continue to burn in northwest Alberta and we could see further interruptions through
the summer and into the fall. We are incredibly proud of how our personnel have responded with sound, safety-focused decision making.
We delivered adjusted funds flow(1) of
$274 million ($0.47 per basic share) and net income of $214 million ($0.37 per basic share) in Q2/2023. Exploration and development expenditures
totaled $171 million in Q2/2023 and we brought 43 (34.9 net) wells onstream. During the second quarter, we generated free cash flow(2) of
$96 million ($0.17 per basic share).
Operating Results
Light Oil - United States
Our light oil assets in the United States are
located in the liquids-rich Eagle Ford formation, in the Texas Gulf Coast Basin. The Ranger acquisition materially increased the scale
of our Eagle Ford operations, adding 162,000 net acres in the crude oil window and on-trend with our non-operated position in the Karnes
Trough. The transaction increased our exposure to premium U.S. Gulf Coast pricing and included substantial infrastructure in place with
low operating and transportation costs.
Production in the Eagle Ford averaged 33,887
boe/d (82% oil and NGLs) during Q2/2023, and includes 11 days of production from the Ranger assets. During the second quarter, we brought
13 (4.9 net) wells onstream, including 2 (2.0 net) operated wells. We expect to bring approximately 24 net operated wells and 8 net non-operated
wells to sales in H2/2023.
Light Oil - Canada
Our light oil production and development in Canada
occurs from the Viking formation in west-central Saskatchewan and east-central Alberta, and the Duvernay formation in the Pembina area
of central Alberta. The Viking is a shallow and highly repeatable light oil resource play with some of the highest operating netbacks
in North America. Our Pembina Duvernay light oil assets are in the demonstration stage of commerciality and offer high operating netbacks,
with the potential for strong economics and organic growth.
Our light oil production in Canada averaged 17,029
boe/d (86% oil and NGLs) during Q2/2023. In the Viking, we brought 28 (28.0 net) wells onstream in Q2/2023 and expect to bring another
46 net wells onstream in H2/2023. In the Pembina Duvernay, we commenced completion activities for the six wells (two-three well pads)
drilled this year. Our completions and facility execution tracked ahead of plan, which allowed for an acceleration of the on-streaming
of wells. Four of the six wells are in the early stages of flow back and are tracking to type curve initial rate expectations. The remaining
two wells are expected to be onstream by mid-August.
Heavy Oil - Canada
Our heavy oil production and development in Canada
occurs within the Bluesky and Spirit River (Clearwater) formations in the Peace River area of northwest Alberta and the Mannville group
of formations in the greater Lloydminster region of east central Alberta and west central Saskatchewan. Our heavy oil business includes
the use of innovative multi-lateral horizontal drilling with strong capital efficiencies. The core of our Clearwater play is located on
the Peavine Métis settlement.
Our heavy oil assets produced a combined 34,955
boe/d (94% oil and NGLs) during Q2/2023. We brought onstream two net wells during the second quarter, which typically has lower activity
due to spring breakup. Our heavy oil development program has ramped up in the third quarter with four rigs running, two at Peavine, one
at Peace River and one at Lloydminster. In H2/2023, we expect to bring 40 net heavy oil wells onstream, 19 at Peavine, 18 at Lloydminster
and 3 at Peace River.
In Q1/2023 we successfully drilled a six-leg Upper
Waseca multi-lateral horizontal exploration well at Cold Lake, Alberta. The well was brought onstream in April and achieved a 30-day
initial production rate of 165 bbl/d of 12.5° API crude oil. The Waseca formation is analogous to Clearwater reservoirs across the
fairway and is highly amenable to open-hole development which drives strong returns and capital efficiencies. We are encouraged by this
initial test result and are planning 3 follow-up wells in the second half of 2023, including a Lower Waseca test. We hold 20 prospective
sections across the play. In addition, we will follow up our successful Q4/2022 Clearwater test well at Morinville, Alberta with two additional
wells in the second half of 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. |
| Baytex Energy Corp. Second Quarter Report 2023 | 5 |
Financial Liquidity
We are well capitalized and have significant liquidity
on our credit facilities. We have a US$1.1 billion revolving credit facility with a maturity date of April 1, 2026, and a US$150
million two-year term loan.
Our total debt(1), which includes our
two series of long-term notes, is $2.6 billion as at June 30, 2023 and we maintain strong liquidity with approximately 40% undrawn
capacity on our revolving credit facility.
Risk Management
We employ a hedge program to help mitigate the volatility in revenue
due to changes in commodity prices.
For Q3/2023 and Q4/2023, we have entered into
hedges on approximately 40% and 35% of our net crude oil exposure, respectively, utilizing a combination of two-way collars with a floor
price of US$60/bbl and a ceiling price of US$100/bbl and a 5,000 bbl/d purchased put at US$60/bbl. For the first half of 2024, we have
entered into hedges on approximately 22% of our net crude oil exposure utilizing two-way collars with a floor price of US$60/bbl and a
ceiling price of US$99/bbl.
A complete listing of our financial derivative contracts can be found
in Note 17 to our Q2/2023 financial statements.
Additional Information
Our condensed consolidated interim unaudited financial
statements for the three and six months ended June 30, 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.sedar.com
and EDGAR at www.sec.gov/ edgar.shtml.
(1) Calculated in accordance with the amended credit facilities
agreement which is available on SEDAR at www.sedar.com.
6 | Baytex Energy Corp. Second Quarter Report 2023 | |
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 press release 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 press release speak only as of the date thereof and are expressly qualified by this
cautionary statement.
Specifically, this press release contains
forward-looking statements relating to but not limited to: that we are poised to deliver a powerful combination of free cash flow and
increased shareholder returns on a per-share basis; we are committed to operational excellence and delivering long-term value and enhanced
shareholder returns; expectations regarding our intention to further strengthen our balance sheet and the allocation of free cash flow,
including with respect to debt repayment and shareholder returns; we expect to generate over $400 million of free cash flow in the second
half of 2023, and approximately $500 million of free cash flow for the full-year 2023; our guidance for 2023 exploration and development
expenditures, production (including production mix by product type), royalty rate, operating, transportation, general and administration
and interest expense and leasing expenditures and asset retirement obligations; we could be impacted by Alberta wildfires through summer
and fall; our plans and expectations in respect of our drilling program, including the number of net wells to be brought on line in H2/2023
and the location of such wells and follow up wells to be drilled at Cold Lake, Alberta and Morinville, Alberta; and our hedging plans.
These forward-looking statements are based
on certain key assumptions regarding, among other things: petroleum and natural gas prices and differentials between light, medium and
heavy oil prices; well production rates and reserve volumes; our ability to add production and reserves through our exploration and development
activities; the future impact of wildfires on our production; that our core assets have more than 10 years development inventory at the
current pace of development; 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, including operating and transportation costs; interest and foreign exchange rates; the continuance of existing and, in certain
circumstances, proposed tax and royalty regimes; our hedging program; our ability to develop our crude oil and natural gas properties
in the manner currently contemplated; and current industry conditions, laws and regulations continuing in effect (or, where changes are
proposed, such changes being adopted as anticipated). Readers are cautioned that such assumptions, although considered reasonable by
Baytex at the time of preparation, may prove to be incorrect.
Actual results achieved will vary from the
information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include,
but are not limited to: risks relating to any unforeseen liabilities of Baytex; that Baytex fails to meet its guidance; the volatility
of oil and natural gas prices and price differentials (including the impacts of Covid-19); risks related to ongoing wildfires; restrictions
or costs imposed by climate change initiatives and the physical risks of climate change; risks associated with our ability to develop
our properties and add reserves; the impact of an energy transition on demand for petroleum productions; changes in income tax or other
laws or government incentive programs; availability and cost of gathering, processing and pipeline systems; retaining or replacing our
leadership and key personnel; the availability and cost of capital or borrowing; risks associated with a third-party operating our Eagle
Ford properties; risks associated with large projects; costs to develop and operate our properties, including transportation costs; public
perception and its influence on the regulatory regime; current or future control, legislation or regulations; new regulations on hydraulic
fracturing; restrictions on or access to water or other fluids; 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; additional risks associated with our thermal heavy oil projects; our ability
to compete with other organizations in the oil and gas industry; risks associated with our use of information technology systems; 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 of counterparty default; the impact of Indigenous claims; risks associated with expansion into new activities;
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,
2022, filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission and in our other public filings.
The above summary of assumptions and risks
related to forward-looking statements has been provided in order to provide shareholders and potential investors with a more complete
perspective on Baytex’s current and future operations and such information may not be appropriate for other purposes.
There is no representation by Baytex that
actual results achieved will be the same in whole or in part as those referenced in the forward-looking statements and Baytex does not
undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information,
future events or otherwise, except as may be required by applicable securities law.
This press release contains information that
may be considered a financial outlook under applicable securities laws about Baytex’s pro forma capitalization upon completion
of the Merger, which are subject to numerous assumptions, risk factors, limitations and qualifications, including those set forth herein.
The actual capitalization of Baytex will vary from the amounts set forth in this press release 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, Baytex undertakes no obligation to
update such financial outlook. The financial outlook contained in this press release was made as of the date of this press release and
was provided for the purpose of providing further information about Baytex’s potential future capitalization upon completion of
the Merger. Readers are cautioned that the financial outlook contained in this press release is not conclusive and is subject to change.
| Baytex Energy Corp. Second Quarter Report 2023 | 7 |
Dividend Advisory
Future dividends and share buybacks, 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) 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.
Specified Financial Measures
In this press release, we refer to certain
financial measures (such as free cash flow, operating netback, 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 natural gas industry,
our determination of these measures may not be comparable with calculations of similar measures for other issuers. In addition, this
press release contains the terms "adjusted funds flow" and "net debt" which are considered capital management measures.
Non-GAAP Financial Measures
Total sales, net of blending and other expense
Total sales, net of blending and other expense
is not a measurement based on GAAP in Canada and 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 not a measurement based
on GAAP in Canada, but is a financial term commonly used in the oil and gas industry. Operating netback is equal to petroleum and natural
gas sales less blending expense, royalties, production and operating expense and transportation expense. Our determination of operating
netback may not be comparable with the calculation of similar measures for other entities. We believe that this measure assists in characterizing
our ability to generate cash margin on a unit of production basis and is a key measure used to evaluate our operating performance.
The following table reconciles total sales, net of blending and
other expense and operating netback to petroleum and natural gas sales.
| |
Three Months Ended June 30 | | |
Six Months Ended June 30 | |
($ thousands) | |
2023 | | |
2022 | | |
2023 | | |
2022 | |
Petroleum and natural gas sales | |
$ | 598,760 | | |
$ | 854,169 | | |
$ | 1,154,096 | | |
$ | 1,527,994 | |
Blending and other expense | |
| (52,995 | ) | |
| (56,895 | ) | |
| (112,676 | ) | |
| (98,335 | ) |
Total sales, net of blending and other expense | |
| 545,765 | | |
| 797,274 | | |
| 1,041,420 | | |
| 1,429,659 | |
Royalties | |
| (107,920 | ) | |
| (171,559 | ) | |
| (201,173 | ) | |
| (294,279 | ) |
Operating expense | |
| (119,438 | ) | |
| (107,426 | ) | |
| (231,846 | ) | |
| (208,192 | ) |
Transportation expense | |
| (14,574 | ) | |
| (11,758 | ) | |
| (31,579 | ) | |
| (20,973 | ) |
Operating netback | |
$ | 303,833 | | |
$ | 506,531 | | |
$ | 576,822 | | |
$ | 906,215 | |
Free cash flow
Free cash flow is not a measurement based
on GAAP in Canada. We define free cash flow as 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, and transaction costs.
Our determination of free cash flow may not be comparable to other issuers. We use free cash flow to evaluate funds available for debt
repayment, common share repurchases, potential future dividends and acquisition and disposition opportunities.
Free cash flow is reconciled to cash flows from operating activities
in the following table.
| |
Three Months Ended June 30 | | |
Six Months Ended June 30 | |
($ thousands) | |
2023 | | |
2022 | | |
2023 | | |
2022 | |
Cash flows from operating activities | |
$ | 192,308 | | |
$ | 360,034 | | |
$ | 377,246 | | |
$ | 559,008 | |
Change in non-cash working capital | |
| 40,795 | | |
| (17,046 | ) | |
| 79,849 | | |
| 60,294 | |
Additions to exploration and evaluation assets | |
| (741 | ) | |
| (2,338 | ) | |
| (1,231 | ) | |
| (5,897 | ) |
Additions to oil and gas properties | |
| (169,963 | ) | |
| (94,295 | ) | |
| (403,099 | ) | |
| (244,558 | ) |
Payments on lease obligations | |
| (1,181 | ) | |
| (1,039 | ) | |
| (2,336 | ) | |
| (2,213 | ) |
Transaction costs | |
| 32,832 | | |
| — | | |
| 41,703 | | |
| — | |
Cash premiums on derivatives | |
| 2,263 | | |
| — | | |
| 2,263 | | |
| — | |
Free cash flow | |
$ | 96,313 | | |
$ | 245,316 | | |
$ | 94,395 | | |
$ | 366,634 | |
8 | Baytex Energy Corp. Second Quarter Report 2023 | |
Non-GAAP Financial Ratios
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 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.
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 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 define net debt to be the sum of our credit facilities and long-term notes
outstanding adjusted for unamortized debt issuance costs adjusted for trade and other payables, cash, and trade and other receivables.
We believe that this measure assists in providing a more complete understanding of our cash liabilities and provide a key measure to
assess our liquidity. We use the principal amounts of the credit facilities and long-term notes outstanding in the calculation of net
debt as these amounts represent our ultimate repayment obligation at maturity. The carrying amount of debt issue costs associated with
the credit facilities and long-term notes is excluded on the basis that these amounts have already been paid by Baytex at inception of
the contract and do not represent an additional source of capital or repayment obligation.
The following table summarizes our calculation
of net debt. | |
| | |
| |
| |
| | |
| |
($ thousands) | |
June 30, 2023 | | |
December 31, 2022 | |
Credit facilities | |
$ | 964,332 | | |
$ | 383,031 | |
Unamortized debt issuance costs - Credit facilities (1) | |
| 22,571 | | |
| 2,363 | |
Long-term notes | |
| 1,563,897 | | |
| 547,598 | |
Unamortized debt issuance costs - Long-term notes (1) | |
| 37,571 | | |
| 6,999 | |
Trade and other payables | |
| 616,608 | | |
| 281,404 | |
Cash | |
| (19,637 | ) | |
| (5,464 | ) |
Trade and other receivables | |
| (370,498 | ) | |
| (228,485 | ) |
Net debt | |
$ | 2,814,844 | | |
$ | 987,446 | |
(1) | Unamortized debt issuance
costs were obtained from Note 7 - Credit Facilities and Note 8 - Long-term Notes from the
consolidated financial statements for the three and six months ended June 30, 2023. |
Adjusted funds flow
Adjusted funds flow is a financial term commonly
used in the oil and gas industry. We define adjusted funds flow as cash flow from operating activities adjusted for changes in non-cash
operating working capital and asset retirement obligations settled. Our determination of adjusted funds flow may not be comparable to
other issuers. We consider adjusted funds flow a key measure that provides a more complete understanding of operating performance and
our ability to generate funds for exploration and development expenditures, debt repayment, settlement of our abandonment obligations
and potential future dividends.
| Baytex Energy Corp. Second Quarter Report 2023 | 9 |
Adjusted funds flow is reconciled to amounts disclosed in the primary
financial statements in the following table.
| |
Three Months Ended June 30 | | |
Six Months Ended June 30 | |
($ thousands) | |
2023 | | |
2022 | | |
2023 | | |
2022 | |
Cash flow from operating activities | |
$ | 192,308 | | |
$ | 360,034 | | |
$ | 377,246 | | |
$ | 559,008 | |
Change in non-cash working capital | |
| 40,795 | | |
| (17,046 | ) | |
| 79,849 | | |
| 60,294 | |
Asset retirement obligations settled | |
| 5,392 | | |
| 2,716 | | |
| 9,518 | | |
| 6,009 | |
Transaction costs | |
| 32,832 | | |
| — | | |
| 41,703 | | |
| — | |
Cash premiums on derivatives | |
| 2,263 | | |
| — | | |
| 2,263 | | |
| — | |
Adjusted funds flow | |
$ | 273,590 | | |
$ | 345,704 | | |
$ | 510,579 | | |
$ | 625,311 | |
Advisory Regarding Oil and Gas Information
Where applicable, 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.
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.
Throughout this press release, “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 six months ended June 30,
2023. The NI 51-101 product types are included as follows: “Heavy Crude Oil” - heavy crude oil and bitumen, “Light
and Medium Crude Oil” - light and medium crude oil, tight oil and condensate, “NGL” - natural gas liquids and “Natural
Gas” - shale gas and conventional natural gas.
| |
Three Months Ended June 30, 2023 | | |
Three Months Ended June 30, 2022 | |
| |
Heavy Crude Oil (bbl/d) | | |
Light and Medium Crude Oil (bbl/d) | | |
NGL (bbl/d) | | |
Natural Gas (Mcf/d) | | |
Oil Equivalent (boe/d) | | |
Heavy Crude Oil (bbl/d) | | |
Light and Medium Crude Oil (bbl/d) | | |
NGL (bbl/d) | | |
Natural Gas (Mcf/d) | | |
Oil Equivalent (boe/d) | |
Canada – Heavy | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Peace River | |
| 9,801 | | |
| 6 | | |
| 49 | | |
| 11,117 | | |
| 11,708 | | |
| 10,216 | | |
| 10 | | |
| 31 | | |
| 12,471 | | |
| 12,336 | |
Lloydminster | |
| 11,398 | | |
| 23 | | |
| — | | |
| 1,228 | | |
| 11,625 | | |
| 11,051 | | |
| 8 | | |
| — | | |
| 1,729 | | |
| 11,347 | |
Peavine | |
| 11,622 | | |
| — | | |
| — | | |
| — | | |
| 11,622 | | |
| 7,319 | | |
| — | | |
| — | | |
| — | | |
| 7,319 | |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Canada - Light | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Viking | |
| — | | |
| 13,265 | | |
| 181 | | |
| 12,105 | | |
| 15,464 | | |
| — | | |
| 14,103 | | |
| 184 | | |
| 13,202 | | |
| 16,487 | |
Duvernay | |
| — | | |
| 675 | | |
| 566 | | |
| 1,946 | | |
| 1,565 | | |
| — | | |
| 801 | | |
| 620 | | |
| 2,007 | | |
| 1,756 | |
Remaining Properties | |
| — | | |
| 643 | | |
| 638 | | |
| 15,647 | | |
| 3,890 | | |
| — | | |
| 753 | | |
| 983 | | |
| 23,627 | | |
| 5,674 | |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
United States | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Eagle Ford | |
| — | | |
| 20,710 | | |
| 7,186 | | |
| 35,946 | | |
| 33,887 | | |
| — | | |
| 17,332 | | |
| 5,650 | | |
| 31,133 | | |
| 28,170 | |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Total | |
| 32,821 | | |
| 35,322 | | |
| 8,620 | | |
| 77,989 | | |
| 89,761 | | |
| 28,586 | | |
| 33,007 | | |
| 7,468 | | |
| 84,169 | | |
| 83,090 | |
10 | Baytex Energy Corp. Second Quarter Report 2023 | |
| |
Six
Months Ended June 30, 2023 | | |
Six
Months Ended June 30, 2022 | |
|
|
|
Heavy
Crude Oil
(bbl/d) |
|
|
|
Light
and
Medium
Crude Oil
(bbl/d) |
|
|
|
NGL
(bbl/d) |
|
|
|
Natural
Gas
(Mcf/d) |
|
|
|
Oil
Equivalent
(boe/d) |
|
|
|
Heavy
Crude Oil
(bbl/d) |
|
|
|
Light
and
Medium
Crude Oil
(bbl/d) |
|
|
|
NGL
(bbl/d) |
|
|
|
Natural
Gas
(Mcf/d) |
|
|
|
Oil
Equivalent
(boe/d) |
|
Canada – Heavy | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Peace River | |
| 10,289 | | |
| 9 | | |
| 51 | | |
| 11,191 | | |
| 12,215 | | |
| 10,898 | | |
| 8 | | |
| 30 | | |
| 11,801 | | |
| 12,902 | |
Lloydminster | |
| 11,522 | | |
| 17 | | |
| — | | |
| 1,223 | | |
| 11,743 | | |
| 10,775 | | |
| 11 | | |
| — | | |
| 1,758 | | |
| 11,079 | |
Peavine | |
| 11,691 | | |
| — | | |
| — | | |
| — | | |
| 11,691 | | |
| 5,248 | | |
| — | | |
| — | | |
| — | | |
| 5,248 | |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Canada - Light | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Viking | |
| — | | |
| 13,948 | | |
| 187 | | |
| 11,864 | | |
| 16,113 | | |
| — | | |
| 14,894 | | |
| 186 | | |
| 12,552 | | |
| 17,172 | |
Duvernay | |
| — | | |
| 868 | | |
| 754 | | |
| 2,283 | | |
| 2,002 | | |
| — | | |
| 896 | | |
| 705 | | |
| 2,174 | | |
| 1,963 | |
Remaining Properties | |
| — | | |
| 658 | | |
| 661 | | |
| 19,001 | | |
| 4,485 | | |
| — | | |
| 810 | | |
| 956 | | |
| 24,158 | | |
| 5,792 | |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
United States | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Eagle Ford | |
| — | | |
| 18,010 | | |
| 6,267 | | |
| 34,455 | | |
| 30,020 | | |
| — | | |
| 16,914 | | |
| 5,675 | | |
| 31,430 | | |
| 27,828 | |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Total | |
| 33,502 | | |
| 33,510 | | |
| 7,920 | | |
| 80,017 | | |
| 88,269 | | |
| 26,921 | | |
| 33,533 | | |
| 7,552 | | |
| 83,873 | | |
| 81,985 | |
Baytex Energy Corp.
Baytex Energy Corp. is an energy company with
headquarters based in Calgary, Alberta and offices in Houston, Texas. The company is engaged in the acquisition, development and production
of crude oil and natural gas in the Western Canadian Sedimentary Basin and in the Eagle Ford in the United States. Baytex’s common
shares trade on the Toronto Stock Exchange and the New York Stock Exchange under the symbol BTE.
For further information about Baytex, please visit our website at www.baytexenergy.com
or contact:
Brian Ector, Senior Vice President, Capital Markets and Investor
Relations
Toll Free Number: 1-800-524-5521
Email: investor@baytexenergy.com
| Baytex Energy Corp. Second Quarter Report 2023 | 11 |
BAYTEX ENERGY CORP.
Management’s Discussion and Analysis
For the three and six months ended June 30, 2023 and 2022
Dated July 27, 2023
The following is management’s discussion
and analysis (“MD&A”) of the operating and financial results of Baytex Energy Corp. for the three and six months ended
June 30, 2023. This information is provided as of July 27, 2023. 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 and six months ended June 30, 2023 ("Q2/2023"
and "YTD 2023") have been compared with the results for the three and six months ended June 30, 2022 ("Q2/2022"
and "YTD 2022"). This MD&A should be read in conjunction with the Company’s unaudited condensed consolidated interim
financial statements (“consolidated financial statements”) as at June 30, 2023, and for the three and six months ended
June 30, 2023 and 2022, its audited comparative consolidated financial statements for the years ended December 31, 2022 and
2021, together with the accompanying notes, and its Annual Information Form ("AIF") for the year ended December 31,
2022. These documents and additional information about Baytex are accessible on the SEDAR website at www.sedar.com and through the U.S.
Securities and Exchange Commission at www.sec.gov. All amounts are in Canadian dollars, unless otherwise stated, and all tabular amounts
are in thousands of Canadian dollars, except for percentages and per common share amounts or as otherwise noted.
In this MD&A, barrel of oil equivalent (“boe”)
amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil, which represents
an energy equivalency conversion method applicable at the burner tip and does not represent a value equivalency at the wellhead. While
it is useful for comparative measures, it may not accurately reflect individual product values and may be misleading if used in isolation.
This MD&A contains forward-looking information
and statements along with certain measures which do not have any standardized meaning in accordance with International Financial Reporting
Standards ("IFRS") as prescribed 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 assets in Texas.
SECOND QUARTER HIGHLIGHTS
Business Combination
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 increases 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 70% weighted
towards high netback light oil and is primarily operated which increases our ability to effectively allocate capital.
Operating and financial results for Q2/2023 include
Ranger operations from the closing date of June 20, 2023 to June 30, 2023. Production from the properties contributed approximately
7,500 boe/d and 3,800 boe/d of production to Q2/2023 and YTD 2023, respectively. The companies began integration in Q2/2023 and operations
have continued in-line with expectations for both the legacy Baytex and Ranger assets. The Merger was primarily funded with a combination
of cash and shares.
We issued 311.4 million common shares and paid
cash consideration of $732.8 million in addition to the assumption of $1.1 billion of Ranger's net debt. The cash portion of the transaction
was funded with our 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. We 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.
12 | Baytex Energy Corp. Second Quarter Report 2023 | |
Second Quarter Operating and Financial Results
Baytex delivered strong operating and financial
results in Q2/2023. Production of 89,761 boe/d for Q2/2023 reflects the production contribution from the Merger with Ranger in addition
to our successful development programs in the U.S. and Canada. Wildfires impacted our operations in Alberta and resulted in the temporary
curtailment of production which reduced production for Q2/2023 by approximately 4,500 boe/d. We invested $170.7 million on exploration
and development expenditures and generated free cash flow(1) of $96.3 million during Q2/2023.
Exploration and development expenditures totaled
$170.7 million in Q2/2023. In the U.S. we invested $74.3 million during Q2/2023 which included $34.1 million of expenditures on our operated
Eagle Ford properties subsequent to acquisition on June 20, 2023 to June 30, 2023. Production in the U.S. averaged 33,887 boe/d
in Q2/2023 compared to 28,170 boe/d in Q2/2022. The increase in U.S. production is due to the production contribution from the properties
acquired from Ranger which added 7,500 boe/d for Q2/2023. Production on our non-operated properties in the U.S. declined slightly relative
to Q2/2022 with overall activity decreasing on our acreage. We invested $96.4 million in Canada in Q2/2023 that was primarily directed
towards light oil development and included completion activities for six Duvernay wells expected to come on production during the third
quarter. Production in Canada averaged 55,874 boe/d during Q2/2023 compared to 54,919 boe/d in Q2/2022. Production for Q2/2023 reflects
the temporary curtailment of production due to Alberta wildfires which reduced production for the period by approximately 4,500 boe/d.
There was no significant physical damage to our operations or assets as a result of the wildfires.
Oil prices decreased
in Q2/2023 on concerns of an economic slowdown causing lower demand for crude oil as central banks continued to increase interest rates
to combat inflation. The WTI and WCS differential benchmarks averaged US$73.78/bbl and US $15.07/bbl during Q2/2023 compared to US$108.41/bbl
and US$12.80/bbl respectively in Q2/2022. Adjusted funds flow(2) of $273.6 million
and cash flows from operating activities of $192.3 million for Q2/2023 reflect commodity prices that were lower relative to Q2/2022 when
we generated adjusted funds flow of $345.7 million and cash flows from operating activities of $360.0 million.
Net debt(2) of $2.8 billion at
June 30, 2023 increased from $987.4 million at December 31, 2022 due to the cash consideration paid and net debt assumed in
conjunction with the Merger with Ranger. We increased our shareholder returns to 50% of free cash flow in conjunction with the closing
of the Merger which will allow us to increase our share buyback program and introduce a dividend. The remainder of our free cash flow
will be allocated to debt reduction.
On June 23, 2023, we renewed our Normal Course
Issuer Bid with the Toronto Stock Exchange for a share buyback program for up to 10% of our public float. Subsequent to June 30,
2023 and through to July 26, 2023, we repurchased 4.7 million common shares at an average price of $4.59 per share. The Board of
Directors has declared a quarterly cash dividend of CDN$0.0225 per share to be paid on October 2, 2023 for shareholders of record
on September 15, 2023. 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 GUIDANCE
Following the Merger with Ranger, Baytex has emerged
as a well-capitalized, diversified oil-weighted North American exploration and production company with a strong free cash flow profile.
For 2023, we continue to forecast exploration and development expenditures of $1,005 to $1,045 million, which are expected to generate
production of 120,500 to 122,500 boe/d. For the second half of 2023, we expect production to average 153,000 to 157,000 boe/d. Our production
mix for the second half of 2023 is forecast to be 84% oil and NGLs (50% light oil, 22% heavy oil and 12% NGLs) and 16% natural gas.
The following tables summarizes our 2023 guidance for production and
exploration and development expenditures.
| |
H1/2023 Actual | | |
H2/2023 Guidance | | |
2023 Guidance | |
Production (boe/d) | |
| 88,269 | | |
| 153,000-157,000 | | |
| 120,500-122,500 | |
Exploration and development expenditures ($ millions) | |
$ | 404 | | |
| $601-$641 | | |
| $1,005-$1,045 | |
We have updated our full-year 2023 cost assumptions
to reflect the Ranger acquisition. Operating expense guidance decreased by 13% to reflect the low cash cost structure of the Ranger assets,
general and administrative expenses increased by 10% on a boe basis to reflect costs associated with Ranger personnel and interest expense
guidance is higher due to the incremental debt associated with the Ranger acquisition and higher interest rates on our credit facilities.
| Baytex Energy Corp. Second Quarter Report 2023 | 13 |
The
following table summarizes our 2023 guidance for expenses, leasing expenditures and asset retirement obligations.
| |
2023 Original Guidance (1) | | |
2023 Revised Guidance | |
Expenses: | |
| | | |
| | |
Average royalty rate (2) | |
| 20.0 - 22.0% | | |
| 21.0 - 22.0% | |
Operating (3) | |
| $14.00 - $14.75/boe | | |
| $12.25 - $12.75/boe | |
Transportation (3) | |
| $1.90 - $2.10/boe | | |
| $2.00 - $2.10/boe | |
General and administrative (3) | |
| $52 million ($1.63/boe) | | |
| $80 million ($1.80/boe) | |
Interest (3) | |
| $65 million ($2.04/boe) | | |
| $150 million ($3.38/boe) | |
| |
| | | |
| | |
Leasing expenditures | |
| $4 million | | |
| $13 million | |
Asset retirement obligations | |
| $25 million | | |
| $25 million | |
(1) | As announced on December 7,
2022. |
(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) | 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. |
14 | Baytex Energy Corp. Second Quarter Report 2023 | |
RESULTS OF OPERATIONS
The Canadian operating segment includes our light
oil assets in Viking and Duvernay, our heavy oil assets in Peace River and Lloydminster and our conventional oil and natural gas assets
in Western Canada. The U.S. operating segment includes our Eagle Ford assets in Texas.
Production
| |
Three Months Ended June 30 | |
| |
2023 | | |
2022 | |
| |
Canada | | |
U.S. | | |
Total | | |
Canada | | |
U.S. | | |
Total | |
Daily Production | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Liquids (bbl/d) | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Light oil and condensate | |
| 14,612 | | |
| 20,710 | | |
| 35,322 | | |
| 15,675 | | |
| 17,332 | | |
| 33,007 | |
Heavy oil | |
| 32,821 | | |
| — | | |
| 32,821 | | |
| 28,586 | | |
| — | | |
| 28,586 | |
Natural Gas Liquids (NGL) | |
| 1,434 | | |
| 7,186 | | |
| 8,620 | | |
| 1,818 | | |
| 5,650 | | |
| 7,468 | |
Total liquids (bbl/d) | |
| 48,867 | | |
| 27,896 | | |
| 76,763 | | |
| 46,079 | | |
| 22,982 | | |
| 69,061 | |
Natural gas (mcf/d) | |
| 42,043 | | |
| 35,946 | | |
| 77,989 | | |
| 53,036 | | |
| 31,133 | | |
| 84,169 | |
Total production (boe/d) | |
| 55,874 | | |
| 33,887 | | |
| 89,761 | | |
| 54,919 | | |
| 28,170 | | |
| 83,090 | |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Production Mix | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Segment as a percent of total | |
| 62 | % | |
| 38 | % | |
| 100 | % | |
| 66 | % | |
| 34 | % | |
| 100 | % |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Light oil and condensate | |
| 26 | % | |
| 61 | % | |
| 39 | % | |
| 29 | % | |
| 62 | % | |
| 40 | % |
Heavy oil | |
| 59 | % | |
| — | % | |
| 37 | % | |
| 52 | % | |
| — | % | |
| 34 | % |
NGL | |
| 3 | % | |
| 21 | % | |
| 10 | % | |
| 3 | % | |
| 20 | % | |
| 9 | % |
Natural gas | |
| 12 | % | |
| 18 | % | |
| 14 | % | |
| 16 | % | |
| 18 | % | |
| 17 | % |
| |
Six Months Ended June 30 | |
| |
2023 | | |
2022 | |
| |
Canada | | |
U.S. | | |
Total | | |
Canada | | |
U.S. | | |
Total | |
Daily Production | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Liquids (bbl/d) | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Light oil and condensate | |
| 15,500 | | |
| 18,010 | | |
| 33,510 | | |
| 16,619 | | |
| 16,914 | | |
| 33,533 | |
Heavy oil | |
| 33,502 | | |
| — | | |
| 33,502 | | |
| 26,921 | | |
| — | | |
| 26,921 | |
Natural Gas Liquids (NGL) | |
| 1,653 | | |
| 6,267 | | |
| 7,920 | | |
| 1,877 | | |
| 5,675 | | |
| 7,552 | |
Total liquids (bbl/d) | |
| 50,655 | | |
| 24,277 | | |
| 74,932 | | |
| 45,417 | | |
| 22,589 | | |
| 68,006 | |
Natural gas (mcf/d) | |
| 45,562 | | |
| 34,455 | | |
| 80,017 | | |
| 52,443 | | |
| 31,430 | | |
| 83,873 | |
Total production (boe/d) | |
| 58,249 | | |
| 30,020 | | |
| 88,269 | | |
| 54,156 | | |
| 27,828 | | |
| 81,985 | |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Production Mix | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Segment as a percent of total | |
| 66 | % | |
| 34 | % | |
| 100 | % | |
| 66 | % | |
| 34 | % | |
| 100 | % |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Light oil and condensate | |
| 27 | % | |
| 60 | % | |
| 38 | % | |
| 31 | % | |
| 61 | % | |
| 41 | % |
Heavy oil | |
| 58 | % | |
| — | % | |
| 38 | % | |
| 50 | % | |
| — | % | |
| 33 | % |
NGL | |
| 3 | % | |
| 21 | % | |
| 9 | % | |
| 3 | % | |
| 20 | % | |
| 9 | % |
Natural gas | |
| 12 | % | |
| 19 | % | |
| 15 | % | |
| 16 | % | |
| 19 | % | |
| 17 | % |
Production was 89,761 boe/d for Q2/2023 and 88,269
boe/d for YTD 2023 compared to 83,090 boe/d for Q2/2022 and 81,985 boe/d for YTD 2022. Production for Q2/2023 and YTD 2023 was higher
than the same periods of 2022 primarily due to the Merger with Ranger which closed on June 20, 2023 and added approximately 7,500
boe/d to Q2/2023 production and 3,800 boe/d to YTD 2023 production.
| Baytex Energy Corp. Second Quarter Report 2023 | 15 |
In
Canada, production was 55,874 boe/d for Q2/2023 and 58,249 boe/d for YTD 2023 compared to 54,919 boe/d for Q2/2022 and 54,156 boe/d for
YTD 2022. Our successful development program and strong well performance from our Clearwater assets at Peavine resulted in a 955 boe/d
increase in production for Q2/2023 and 4,093 boe/d for YTD 2023 relative to the comparative periods of 2022. Production for Q2/2023 reflects
the impact of wildfires in northwest Alberta which resulted in temporary shut-ins that reduced production by approximately 4,500 boe/d
for Q2/2023.
In the U.S., production was 33,887 boe/d for Q2/2023
and 30,020 boe/d for YTD 2023 compared to 28,170 boe/d for Q2/2022 and 27,828 boe/d for YTD 2022. The increase in production in 2023 relative
to 2022 is primarily due to the production contribution from the Merger with Ranger which added approximately 7,500 boe/d to Q2/2023 production
and 3,800 boe/d to YTD 2023 production. Production from the acquired Eagle Ford assets is approximately 70% weighted towards high netback
light oil and is primarily operated. U.S. results, excluding the Merger with Ranger, for Q2/2023 and YTD 2023 were in line with expectations
and reflect reduced development activity on our non-operated Eagle Ford properties.
Total production of 88,269 boe/d for YTD 2023
is consistent with expectations and we expect production of 153,000-157,000 boe/d for the second half of 2023 and 120,500-122,500 boe/d
for 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
during Q2/2023 and YTD 2023 as central banks continue to raise interest rates to combat inflation combined with expectations for slower
economic activity and demand for crude oil. As a result, the WTI benchmark price averaged US$73.78/bbl for Q2/2023 and US$74.96/bbl for
YTD 2023 compared to Q2/2022 and YTD 2022 when WTI was higher due to uncertainty around global supply caused by Russia's invasion of Ukraine
and averaged US$108.41/bbl and US$101.35/bbl, respectively.
We compare the price received for our U.S. crude
oil production to the Magellan East Houston ("MEH") stream at Houston, Texas which is a representative benchmark for light oil
pricing at the U.S. Gulf coast. The MEH benchmark averaged US$75.01/bbl during Q2/2023 and US$76.22/bbl during YTD 2023 which is lower
than US$112.41/bbl during Q2/2022 and US$104.56/bbl during YTD 2022. The MEH benchmark trades at a premium to WTI as a result of access
to global markets. The MEH benchmark premium to WTI was US$1.23/bbl and US$1.26/bbl for Q2/2023 and YTD 2023 compared to premiums of US$4.00/bbl
and US$3.21/bbl for Q2/2022 and YTD 2022, respectively. The MEH benchmark traded at a lower premium to WTI in both periods of 2023 as
a result of reduced refinery demand on the Gulf Coast relative to the same periods of 2022.
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
from period to period based on production levels in Western Canada along with North American refinery demand. Canadian oil differentials
were wider in 2023 relative to 2022 due to reduced demand caused by planned and unplanned refinery maintenance along with increased supply
following record releases from the U.S. Strategic Petroleum Reserve.
We compare the price received for our light oil
production in Canada to the Edmonton par benchmark oil price. The Edmonton par price averaged $95.13/bbl during Q2/2023 and $97.09/bbl
during YTD 2023 compared to $137.79/bbl during Q2/2022 and $126.72/bbl during YTD 2022. Edmonton par traded at a discount to WTI of US$2.95/bbl
for Q2/2023 and US$2.91/bbl for YTD 2023 compared to a discount of US$0.47/bbl for Q2/2022 and US$1.68/bbl for YTD 2022.
We compare the price received for our heavy oil
production in Canada to the WCS heavy oil benchmark. The WCS heavy oil price for Q2/2023 and YTD 2023 averaged $78.85/bbl and $74.16/bbl,
respectively, compared to $122.05/bbl and $111.48/bbl for the same periods of 2022. The WCS heavy oil differential was US$15.07/bbl in
Q2/2023 and US$19.92/bbl in YTD 2023 compared to discounts of US$12.80/bbl for Q2/2022 and US$13.67/bbl for YTD 2022.
Natural Gas
Reduced demand for North American gas resulted
in lower prices 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$2.10/mmbtu for
Q2/2023 and US$2.76/mmbtu for YTD 2023 compared to US$7.17/ mmbtu for Q2/2022 and US$6.06/mmbtu for YTD 2022.
16 | Baytex Energy Corp. Second Quarter Report 2023 | |
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 $2.35/mcf during Q2/2023 and $3.34/mcf during YTD 2023
which is lower than $6.27/mcf for Q2/2022 and $5.43/mcf for YTD 2022.
The following tables compare select benchmark
prices and our average realized selling prices for the three and six months ended June 30, 2023 and 2022.
| |
Three Months Ended June 30 | | |
Six Months Ended June 30 | |
| |
2023 | | |
2022 | | |
Change | | |
2023 | | |
2022 | | |
Change | |
Benchmark Averages | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
WTI oil (US$/bbl) (1) | |
| 73.78 | | |
| 108.41 | | |
| (34.63 | ) | |
| 74.96 | | |
| 101.35 | | |
| (26.39 | ) |
MEH oil (US$/bbl) (2) | |
| 75.01 | | |
| 112.41 | | |
| (37.40 | ) | |
| 76.22 | | |
| 104.56 | | |
| (28.34 | ) |
MEH oil differential to WTI (US$/bbl) | |
| 1.23 | | |
| 4.00 | | |
| (2.77 | ) | |
| 1.26 | | |
| 3.21 | | |
| (1.95 | ) |
Edmonton par oil ($/bbl) (3) | |
| 95.13 | | |
| 137.79 | | |
| (42.66 | ) | |
| 97.09 | | |
| 126.72 | | |
| (29.63 | ) |
Edmonton par oil differential to WTI (US$/bbl) | |
| (2.95 | ) | |
| (0.47 | ) | |
| (2.48 | ) | |
| (2.91 | ) | |
| (1.68 | ) | |
| (1.23 | ) |
WCS heavy oil ($/bbl) (4) | |
| 78.85 | | |
| 122.05 | | |
| (43.20 | ) | |
| 74.16 | | |
| 111.48 | | |
| (37.32 | ) |
WCS heavy oil differential to WTI (US$/bbl) | |
| (15.07 | ) | |
| (12.80 | ) | |
| (2.27 | ) | |
| (19.92 | ) | |
| (13.67 | ) | |
| (6.25 | ) |
AECO natural gas ($/mcf) (5) | |
| 2.35 | | |
| 6.27 | | |
| (3.92 | ) | |
| 3.34 | | |
| 5.43 | | |
| (2.09 | ) |
NYMEX natural gas (US$/mmbtu) (6) | |
| 2.10 | | |
| 7.17 | | |
| (5.07 | ) | |
| 2.76 | | |
| 6.06 | | |
| (3.30 | ) |
CAD/USD average exchange rate | |
| 1.3431 | | |
| 1.2766 | | |
| 0.0665 | | |
| 1.3475 | | |
| 1.2714 | | |
| 0.0761 | |
(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. |
| |
Three Months Ended June 30 | |
| |
2023 | |
2022 | |
| |
Canada | |
U.S. | |
Total | |
Canada | |
U.S. | |
Total | |
Average Realized Sales Prices | |
| | |
| | |
| | |
| | |
| | |
| | |
Light oil and condensate ($/bbl) (1) | |
$ | 93.98 | |
$ | 97.55 | |
$ | 96.07 | |
$ | 135.29 | |
$ | 141.14 | |
$ | 138.36 | |
Heavy oil, net of blending and other expense ($/bbl) (2) | |
| 66.45 | |
| — | |
| 66.45 | |
| 111.18 | |
| — | |
| 111.18 | |
NGL ($/bbl) (1) | |
| 28.92 | |
| 25.07 | |
| 25.71 | |
| 50.09 | |
| 48.42 | |
| 48.83 | |
Natural gas ($/mcf) (1) | |
| 2.64 | |
| 2.52 | |
| 2.58 | |
| 7.01 | |
| 8.99 | |
| 7.74 | |
Total sales, net of blending and other expense ($/boe) (2) | |
$ | 66.34 | |
$ | 67.60 | |
$ | 66.82 | |
$ | 104.91 | |
$ | 106.48 | |
$ | 105.44 | |
| |
Six Months Ended June 30 | |
| |
2023 | |
2022 | |
| |
Canada | |
U.S. | |
Total | |
Canada | |
U.S. | |
Total | |
Average Realized Sales Prices | |
| | |
| | |
| | |
| | |
| | |
| | |
Light oil and condensate ($/bbl) (1) | |
$ | 96.74 | |
$ | 99.96 | |
$ | 98.47 | |
$ | 124.05 | |
$ | 131.77 | |
$ | 127.95 | |
Heavy oil, net of blending and other expense ($/bbl) (2) | |
| 58.69 | |
| — | |
| 58.69 | |
| 101.01 | |
| — | |
| 101.01 | |
NGL ($/bbl) (1) | |
| 32.86 | |
| 28.35 | |
| 29.29 | |
| 46.43 | |
| 45.66 | |
| 45.85 | |
Natural gas ($/mcf) (1) | |
| 3.12 | |
| 3.23 | |
| 3.17 | |
| 5.84 | |
| 7.52 | |
| 6.47 | |
Total sales, net of blending and other expense ($/boe) (2) | |
$ | 62.91 | |
$ | 69.60 | |
$ | 65.18 | |
$ | 95.55 | |
$ | 97.90 | |
$ | 96.34 | |
(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. |
| Baytex Energy Corp. Second Quarter Report 2023 | 17 |
Average Realized Sales Prices
Our total sales, net of blending and other expense
per boe(1) was $66.82/boe for Q2/2023 and $65.18/bbl for YTD 2023 compared to $105.44/boe for Q2/2022 and $96.34/boe for
YTD 2022. In Canada, our realized price of $66.34/boe for Q2/2023 was $38.57/ boe lower than $104.91/boe for Q2/2022. Our realized price
in the U.S. was $67.60/boe in Q2/2023 which is $38.88/boe lower than $106.48/boe in Q2/2022. Lower North American benchmark oil prices
was the primary factor that resulted in lower realized pricing for our operations in Canada and the U.S. in Q2/2023 and YTD 2023 relative
to the same periods of 2022.
We compare our light oil realized price in Canada
to the Edmonton par benchmark price. Our realized light oil and condensate price(2) was $93.98/bbl for Q2/2023 and $96.74/bbl
for YTD 2023 compared to $135.29/bbl for Q2/2022 and $124.05/bbl for YTD 2022. The decrease in our realized light oil and condensate price
for Q2/2023 and YTD 2023 was primarily a result of lower benchmark prices and represents discounts to the Edmonton par price of $1.15/bbl
and $0.35/bbl for Q2/2023 and YTD 2023, respectively, which are narrower than discounts of $2.50/bbl in Q2/2022 and $2.67/bbl in YTD 2022
due to strong realized pricing for our Viking light oil production in Saskatchewan.
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 $97.55/bbl for Q2/2023 and $99.96/bbl
for YTD 2023 compared to $141.14/bbl for Q2/2022 and $131.77/bbl for YTD 2022. Expressed in U.S. dollars, our realized light oil and condensate
price of US$72.63/bbl for Q2/2023 and US$74.18/bbl for YTD 2023 represents discounts to MEH of US$2.38/bbl and US$2.04/bbl for Q2/2023
and YTD 2023, respectively, compared to discounts of US$1.85/bbl for Q2/2022 and US$0.92/bbl for YTD 2022.
Our realized heavy oil price, net of blending
and other expense(1) averaged $66.45/bbl in Q2/2023 and $58.69/bbl in YTD 2023 compared to $111.18/bbl in Q2/2022 and
$101.01/bbl in YTD 2022. Our realized heavy oil, net of blending and other expense for Q2/2023 and YTD 2023 was $44.73/bbl and $42.32/bbl
lower relative to Q2/2022 and YTD 2022, respectively, compared with a $43.20/bbl and $37.32/bbl decrease in the WCS benchmark price over
the same periods. Our realized price decreased more than the benchmark price due to higher per unit blending costs relative to the WCS
benchmark in both periods of 2023 compared to same periods of 2022.
Our realized NGL price as a percentage of WTI
can vary from period to period based on the product mix of our NGL volumes and changes in the market prices for the underlying products.
Our realized NGL price(2) was $25.71/bbl in Q2/2023 or 26% of WTI (expressed in Canadian dollars) and $29.29/bbl in YTD
2023 or 29% of WTI (expressed in Canadian dollars) compared to $48.83/ bbl or 35% of WTI (expressed in Canadian dollars) in Q2/2022 and
$45.85/bbl or 36% of WTI (expressed in Canadian dollars) in YTD 2022. Our realized NGL price in Canada and the U.S. was lower as a percentage
of WTI in Q2/2023 and YTD 2023 due to lower demand for NGL products relative to the same periods of 2022.
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 $2.64/mcf for Q2/2023 and $3.12/mcf for YTD 2023 compared to $7.01/mcf in Q2/2022 and $5.84/mcf
for YTD 2022. In the U.S., our realized natural gas price was US$1.88/mcf for Q2/2023 and US$2.40/mcf for YTD 2023 compared to US$7.04/mcf
for Q2/2022 and US$5.91/mcf for YTD 2022. The decrease in our realized gas price in Canada and the U.S. is relatively consistent with
the decreases in the AECO monthly and NYMEX monthly benchmark prices in 2023 compared to the same periods of 2022.
(1) | Specified financial measure
that does not have any standardized meaning prescribed by IFRS and may not be comparable
with the calculation of similar measures presented by other entities. Refer to the Specified
Financial Measures section in this MD&A for further information. |
(2) | Calculated as light oil
and condensate, NGL or natural gas sales divided by barrels of oil equivalent production
volume for the applicable period. |
18 | Baytex Energy Corp. Second Quarter Report 2023 | |
PETROLEUM AND NATURAL GAS SALES
| |
Three Months Ended June 30 | |
| |
2023 | | |
2022 | |
($ thousands) | |
Canada | | |
U.S. | | |
Total | | |
Canada | | |
U.S. | | |
Total | |
Oil sales | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Light oil and condensate | |
$ | 124,965 | | |
$ | 183,845 | | |
$ | 308,810 | | |
$ | 192,986 | | |
$ | 222,606 | | |
$ | 415,592 | |
Heavy oil | |
| 251,449 | | |
| — | | |
| 251,449 | | |
| 346,101 | | |
| — | | |
| 346,101 | |
NGL | |
| 3,772 | | |
| 16,391 | | |
| 20,163 | | |
| 8,288 | | |
| 24,895 | | |
| 33,183 | |
Total oil sales | |
| 380,186 | | |
| 200,236 | | |
| 580,422 | | |
| 547,375 | | |
| 247,501 | | |
| 794,876 | |
Natural gas sales | |
| 10,106 | | |
| 8,232 | | |
| 18,338 | | |
| 33,822 | | |
| 25,471 | | |
| 59,293 | |
Total petroleum and natural gas sales | |
| 390,292 | | |
| 208,468 | | |
| 598,760 | | |
| 581,197 | | |
| 272,972 | | |
| 854,169 | |
Blending and other expense | |
| (52,995 | ) | |
| — | | |
| (52,995 | ) | |
| (56,895 | ) | |
| — | | |
| (56,895 | ) |
Total sales, net of blending and other | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
expense (1) | |
$ | 337,297 | | |
$ | 208,468 | | |
$ | 545,765 | | |
$ | 524,302 | | |
$ | 272,972 | | |
$ | 797,274 | |
| |
Six Months Ended June 30 | |
| |
2023 | | |
2022 | |
($ thousands) | |
Canada | | |
U.S. | | |
Total | | |
Canada | | |
U.S. | | |
Total | |
Oil sales | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Light oil and condensate | |
$ | 271,420 | | |
$ | 325,855 | | |
$ | 597,275 | | |
$ | 373,141 | | |
$ | 403,426 | | |
$ | 776,567 | |
Heavy oil | |
| 468,534 | | |
| — | | |
| 468,534 | | |
| 590,539 | | |
| — | | |
| 590,539 | |
NGL | |
| 9,832 | | |
| 32,165 | | |
| 41,997 | | |
| 15,772 | | |
| 46,902 | | |
| 62,674 | |
Total oil sales | |
| 749,786 | | |
| 358,020 | | |
| 1,107,806 | | |
| 979,452 | | |
| 450,328 | | |
| 1,429,780 | |
Natural gas sales | |
| 26,128 | | |
| 20,162 | | |
| 46,290 | | |
| 55,449 | | |
| 42,765 | | |
| 98,214 | |
Total petroleum and natural gas sales | |
| 775,914 | | |
| 378,182 | | |
| 1,154,096 | | |
| 1,034,901 | | |
| 493,093 | | |
| 1,527,994 | |
Blending and other expense | |
| (112,676 | ) | |
| — | | |
| (112,676 | ) | |
| (98,335 | ) | |
| — | | |
| (98,335 | ) |
Total sales, net of blending and other | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
expense (1) | |
$ | 663,238 | | |
$ | 378,182 | | |
$ | 1,041,420 | | |
$ | 936,566 | | |
$ | 493,093 | | |
$ | 1,429,659 | |
(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. |
Total sales, net of blending and other expense,
of $545.8 million for Q2/2023 decreased $251.5 million from $797.3 million reported for Q2/2022 while total sales, net of blending and
other expense, of $1.0 billion for YTD 2023 decreased $388.2 million from $1.4 billion reported for YTD 2022. The decrease in total sales
in both periods of 2023 relative to the same periods of 2022 reflects lower benchmark prices which more than offset the increase in production
from our successful development programs along with the contribution of the Ranger assets.
In Canada, total sales, net of blending and other
expense, was $337.3 million for Q2/2023 which is a decrease of $187.0 million from $524.3 million reported for Q2/2022. The decrease in
total petroleum and natural gas sales was the result of lower realized pricing for Q2/2023 relative to Q2/2022 which resulted in a $196.1
million decrease in total sales, net of blending and other expense while higher production resulted in a $9.1 million increase in total
sales, net of blending and other expense, relative to Q2/2022. Lower benchmark prices was the primary factor contributing to our total
sales, net of blending and other expense, decreasing to $663.2 million in YTD 2023 from $936.6 million in YTD 2022.
In the U.S., petroleum and natural gas sales were
$208.5 million for Q2/2023 which is a decrease of $64.5 million from $273.0 million reported for Q2/2022. Higher production in Q2/2023
relative to Q2/2022 contributed to a $55.4 million increase in total sales which was more than offset by lower realized pricing which
resulted in a $119.9 million decrease in total sales for Q2/2023 relative to Q2/2022. The decrease in realized pricing in YTD 2023 resulted
in petroleum and natural gas sales of $378.2 million for YTD 2023 compared to $493.1 million in YTD 2022 despite higher production in
YTD 2023 relative to YTD 2022.
| Baytex Energy Corp. Second Quarter Report 2023 | 19 |
ROYALTIES
Royalties are paid to various government entities
and to land and mineral rights owners. Royalties are calculated based on gross revenues or on operating netbacks less capital investment
for specific heavy oil projects and are generally expressed as a percentage of total sales, net of blending and other expense. The actual
royalty rates can vary for a number of reasons, including the commodity produced, royalty contract terms, commodity price level, royalty
incentives and the area or jurisdiction. The following table summarizes our royalties and royalty rates for the three and six months ended
June 30, 2023 and 2022.
| |
Three Months Ended June 30 | |
| |
2023 | | |
2022 | |
($ thousands except for % and per boe) | |
Canada | | |
U.S. | | |
Total | | |
Canada | | |
U.S. | | |
Total | |
Royalties | |
$ | 47,309 | | |
$ | 60,611 | | |
$ | 107,920 | | |
$ | 91,133 | | |
$ | 80,426 | | |
$ | 171,559 | |
Average royalty rate (1)(2) | |
| 14.0 | % | |
| 29.1 | % | |
| 19.8 | % | |
| 17.4 | % | |
| 29.5 | % | |
| 21.5 | % |
Royalties per boe (3) | |
$ | 9.30 | | |
$ | 19.66 | | |
$ | 13.21 | | |
$ | 18.24 | | |
$ | 31.37 | | |
$ | 22.69 | |
| |
Six Months Ended June 30 | |
| |
2023 | | |
2022 | |
($ thousands except for % and per boe) | |
Canada | | |
U.S. | | |
Total | | |
Canada | | |
U.S. | | |
Total | |
Royalties | |
$ | 91,164 | | |
$ | 110,009 | | |
$ | 201,173 | | |
$ | 148,809 | | |
$ | 145,470 | | |
$ | 294,279 | |
Average royalty rate (1)(2) | |
| 13.7 | % | |
| 29.1 | % | |
| 19.3 | % | |
| 15.9 | % | |
| 29.5 | % | |
| 20.6 | % |
Royalties per boe (3) | |
$ | 8.65 | | |
$ | 20.25 | | |
$ | 12.59 | | |
$ | 15.18 | | |
$ | 28.88 | | |
$ | 19.83 | |
(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 Q2/2023 were $107.9 million or 19.8%
of total sales, net of blending and other expense, compared to $171.6 million or 21.5% for Q2/2022. Total royalties for YTD 2023 were
$201.2 million or 19.3% of total sales, net of blending and other expense, compared to $294.3 million or 20.6% for YTD 2022. The decrease
in total royalties in both periods of 2023 is primarily a result of lower benchmark prices along with a lower royalty rate on our Canadian
production relative to the same periods of 2022. Our royalty rates of 19.8% for Q2/2023 and 19.3% for YTD 2023 were lower than 21.5% for
Q2/2022 and 20.6% for YTD 2022.
Our Canadian royalty rates of 14.0% for Q2/2023
and 13.7% for YTD 2023 were lower than 17.4% for Q2/2022 and 15.9% for YTD 2022 due to lower benchmark commodity prices which resulted
in a lower royalty rate on our Canadian properties in 2023 relative to 2022. In the U.S., royalties averaged 29.1% of total sales for
Q2/2023 and YTD 2023 respectively, which is slightly lower than 29.5% for Q2/2022 and YTD 2022 due to the production contributed by the
acquired Ranger assets which has a lower royalty rate relative to our legacy non-operated Eagle Ford assets.
Our average royalty rate of 19.3% for YTD 2023
is consistent with expectations and we have updated our annual guidance to 21.0 - 22.0% for 2023 which reflects the royalty rate on the
properties acquired from Ranger which has a higher royalty rate than our corporate average.
OPERATING EXPENSE
| |
Three Months Ended June 30 | |
| |
2023 | | |
2022 | |
($ thousands except for per boe) | |
Canada | | |
U.S. | | |
Total | | |
Canada | | |
U.S. | | |
Total | |
Operating expense | |
$ | 91,354 | | |
$ | 28,084 | | |
$ | 119,438 | | |
$ | 82,471 | | |
$ | 24,955 | | |
$ | 107,426 | |
Operating expense per boe (1) | |
$ | 17.97 | | |
$ | 9.11 | | |
$ | 14.62 | | |
$ | 16.50 | | |
$ | 9.73 | | |
$ | 14.21 | |
| |
Six Months Ended June 30 | |
| |
2023 | | |
2022 | |
($ thousands except for per boe) | |
Canada | | |
U.S. | | |
Total | | |
Canada | | |
U.S. | | |
Total | |
Operating expense | |
$ | 182,534 | | |
$ | 49,312 | | |
$ | 231,846 | | |
$ | 161,011 | | |
$ | 47,181 | | |
$ | 208,192 | |
Operating expense per boe (1) | |
$ | 17.31 | | |
$ | 9.08 | | |
$ | 14.51 | | |
$ | 16.43 | | |
$ | 9.37 | | |
$ | 14.03 | |
(1) | Operating expense per boe
is calculated as operating expense divided by barrels of oil equivalent production volume
for the applicable period. |
20 | Baytex Energy Corp. Second Quarter Report 2023 | |
Total
operating expense was $119.4 million ($14.62/boe) for Q2/2023 and $231.8 million ($14.51/boe) for YTD 2023 compared to $107.4 million
($14.21/boe) for Q2/2022 and $208.2 million ($14.03/boe) for YTD 2022. Operating expense for both periods of 2023 increased in total and
per boe reflecting increased production and cost inflation throughout our operations in 2023 relative to 2022.
In Canada, operating expense was $91.4 million
($17.97/boe) for Q2/2023 and $182.5 million ($17.31/boe) for YTD 2023 compared to $82.5 million ($16.50/boe) for Q2/2022 and $161.0 million
($16.43/boe) for YTD 2022. Total operating expenses were higher in Canada as a result of higher production along with slightly higher
per boe costs due to inflation.
U.S. operating expense was $28.1 million ($9.11/boe)
for Q2/2023 and $49.3 million ($9.08/boe) for YTD 2023 compared to $25.0 million ($9.73/boe) for Q2/2022 and $47.2 million ($9.37/boe)
in YTD 2022. Our U.S. operating expenses expressed in U.S. dollars, per unit operating expense was US$6.78/boe in Q2/2023 and US$6.74/boe
in YTD 2023 which was lower than US$7.62/ boe for Q2/2022 and US$7.37/boe in YTD 2022 as a result of lower workover activity in 2023.
Operating expense of $14.51 for YTD 2023 is consistent
with expectations and we have updated our annual guidance range to $12.25 - $12.75/boe for 2023 which reflects the lower operating cost
structure of the Ranger assets.
TRANSPORTATION EXPENSE
Transportation expense includes the costs to move
production from the field to the sales point. The largest component of transportation expense relates to the trucking of oil in Canada
to pipeline and rail terminals which can vary from period to period depending on hauling distances as we seek to optimize sales prices
and trucking rates. Transportation expense in our U.S. operations is primarily the costs incurred to deliver our production via truck
or pipeline to a centralized sales point.
The following table compares our transportation expense for the three
and six months ended June 30, 2023 and 2022.
| |
Three Months Ended June 30 | |
| |
2023 | | |
2022 | |
($ thousands except for per boe) | |
Canada | | |
U.S. | | |
Total | | |
Canada | | |
U.S. | | |
Total | |
Transportation expense | |
$ | 13,240 | | |
$ | 1,334 | | |
$ | 14,574 | | |
$ | 11,758 | | |
$ | — | | |
$ | 11,758 | |
Transportation expense per boe (1) | |
$ | 2.60 | | |
$ | 0.43 | | |
$ | 1.78 | | |
$ | 2.35 | | |
$ | — | | |
$ | 1.56 | |
| |
Six Months Ended June 30 | |
| |
2023 | | |
2022 | |
($ thousands except for per boe) | |
Canada | | |
U.S. | | |
Total | | |
Canada | | |
U.S. | | |
Total | |
Transportation expense | |
$ | 30,245 | | |
$ | 1,334 | | |
$ | 31,579 | | |
$ | 20,973 | | |
$ | — | | |
$ | 20,973 | |
Transportation expense per boe (1) | |
$ | 2.87 | | |
$ | 0.25 | | |
$ | 1.98 | | |
$ | 2.14 | | |
$ | — | | |
$ | 1.41 | |
(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 $14.6 million ($1.78/boe)
for Q2/2023 and $31.6 million ($1.98/boe) for YTD 2023 compared to $11.8 million ($1.56/boe) for Q2/2022 and $21.0 million ($1.41/boe)
for YTD 2022. In Canada, total transportation expense and per unit costs are higher in Q2/2023 and YTD 2023 as a result of additional
heavy oil production along with higher trucking rates relative to the same periods of 2022. Transportation expense in the U.S. is consistent
with expectations for Q2/2023 and YTD 2023 and reflects trucking and pipeline transportation costs on our Eagle Ford operations acquired
from Ranger. Per unit transportation expense of $1.98/boe for YTD 2023 is consistent with expectations and we have updated our annual
guidance range to $2.00 - $2.10/boe to reflect the incremental transportation costs associated with the properties acquired from Ranger.
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 $53.0 million for
Q2/2023 and $112.7 million for YTD 2023 compared to $56.9 million for Q2/2022 and $98.3 million for YTD 2022. The increase in blending
and other expense is primarily a result of higher heavy oil production and pipeline shipments in YTD 2023 relative to YTD 2022, while
Q2/2023 was consistent with Q2/2022 due to curtailed heavy oil production from the wildfires in Alberta.
| Baytex Energy Corp. Second Quarter Report 2023 | 21 |
FINANCIAL DERIVATIVES
As part of our normal operations, we are exposed
to movements in commodity prices, foreign exchange rates, interest rates and changes in our share price. In an effort to manage these
exposures, we utilize various financial derivative contracts which are intended to partially reduce the volatility in our revenue. Contracts
settled in the period result in realized gains or losses based on the market price compared to the contract price and the notional volume
outstanding. Changes in the fair value of unsettled contracts are reported as unrealized gains or losses in the period as the forward
markets fluctuate and as new contracts are executed. The following table summarizes the results of our financial derivative contracts
for the three and six months ended June 30, 2023 and 2022.
| |
Three Months Ended June 30 | | |
Six Months Ended June 30 | |
($ thousands) | |
2023 | | |
2022 | | |
Change | | |
2023 | | |
2022 | | |
Change | |
Realized financial derivatives gain (loss) | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Crude oil | |
$ | 16,363 | | |
$ | (112,071 | ) | |
$ | 128,434 | | |
$ | 21,778 | | |
$ | (191,597 | ) | |
$ | 213,375 | |
Natural gas | |
| 2 | | |
| (11,971 | ) | |
| 11,973 | | |
| 2 | | |
| (16,811 | ) | |
| 16,813 | |
Total | |
$ | 16,365 | | |
$ | (124,042 | ) | |
$ | 140,407 | | |
$ | 21,780 | | |
$ | (208,408 | ) | |
$ | 230,188 | |
Unrealized financial derivatives gain (loss) | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Crude oil | |
$ | (17,124 | ) | |
$ | 47,816 | | |
$ | (64,940 | ) | |
$ | (7,914 | ) | |
$ | (91,502 | ) | |
$ | 83,588 | |
Natural gas | |
| (2,279 | ) | |
| 9,363 | | |
| (11,642 | ) | |
| (2,279 | ) | |
| (7,271 | ) | |
| 4,992 | |
Equity total return swap ("Equity TRS") | |
| — | | |
| 1,589 | | |
| (1,589 | ) | |
| — | | |
| 1,280 | | |
| (1,280 | ) |
Total | |
$ | (19,403 | ) | |
$ | 58,768 | | |
$ | (78,171 | ) | |
$ | (10,193 | ) | |
$ | (97,493 | ) | |
$ | 87,300 | |
Total financial derivatives gain (loss) | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Crude oil | |
$ | (761 | ) | |
$ | (64,255 | ) | |
$ | 63,494 | | |
$ | 13,864 | | |
$ | (283,099 | ) | |
$ | 296,963 | |
Natural gas | |
| (2,277 | ) | |
| (2,608 | ) | |
| 331 | | |
| (2,277 | ) | |
| (24,082 | ) | |
| 21,805 | |
Equity TRS | |
| — | | |
| 1,589 | | |
| (1,589 | ) | |
| — | | |
| 1,280 | | |
| (1,280 | ) |
Total | |
$ | (3,038 | ) | |
$ | (65,274 | ) | |
$ | 62,236 | | |
$ | 11,587 | | |
$ | (305,901 | ) | |
$ | 317,488 | |
We recorded a total financial derivative loss
of $3.0 million for Q2/2023 and a gain of $11.6 million for YTD 2023 compared to a loss of $65.3 million for Q2/2022 and $305.9 million
for YTD 2022. The realized financial derivatives gain of $16.4 million for Q2/2023 and $21.8 million for YTD 2023 were primarily a result
of the market prices for crude oil and natural gas settling at levels below those set in our derivative contracts. The unrealized loss
of $19.4 million for Q2/2023 and $10.2 million for YTD 2023 reflect changes in forecasted crude oil pricing used to revalue the unsettled
notional volume outstanding on our crude oil contracts in place at June 30, 2023 relative to March 31, 2023 and December 31,
2022. The fair value of our financial derivative contracts resulted in a net asset of $24.6 million at June 30, 2023 compared to
a net asset of $19.3 million at March 31, 2023 and a net liability of $10.1 million at December 31, 2022.
22 | Baytex Energy Corp. Second Quarter Report 2023 | |
We
had the following commodity financial derivative contracts as at July 27, 2023.
|
| Period | |
Volume | |
Price/Unit (1) |
| |
Index |
|
Oil |
| | |
| |
|
| |
|
|
Basis differential (2) |
| July 2023 to Dec 2023 | |
1,500 bbl/d | |
WTI less US$2.50/bbl |
| |
MSW |
|
Basis differential (2)(3) |
| Jan 2024 to Dec 2024 | |
1,500 bbl/d | |
WTI less US$2.65/bbl |
| |
MSW |
|
Basis differential (2) |
| July 2023 to Dec 2023 | |
2,000 bbl/d | |
WTI less US$14.98/bbl |
| |
WCS |
|
Basis differential (2) |
| Aug 2023 to Dec 2023 | |
6,000 bbl/d | |
WTI less US$13.62/bbl |
| |
WCS |
|
|
| | |
| |
Baytex pays: WCS differential at Hardisty |
| |
|
|
|
| | |
| |
Baytex receives: WCS differential at Houston less |
| |
|
|
Basis differential (2) |
| July 2023 to Dec 2023 | |
5,000 bbl/d | |
US$8.10/bbl |
| |
WCS |
|
|
| | |
| |
Baytex pays: WCS differential at Hardisty |
| |
|
|
|
| | |
| |
Baytex receives: WCS differential at Houston less |
| |
|
|
Basis differential (2) |
| Jan 2024 to Jun 2024 | |
4,000 bbl/d | |
US$8.10/bbl |
| |
WCS |
|
Put option |
| July 2023 to Dec 2023 | |
5,000 bbl/d | |
US$60.00 |
| |
WTI |
|
Collar |
| July 2023 to Dec 2023 | |
15,500 bbl/d | |
US$60.00/US$100.00 |
| |
WTI |
|
Collar |
| July 2023 to Sep 2023 | |
19,862 bbl/d | |
US$60.00/US$100.00 |
| |
WTI |
|
Collar |
| Oct 2023 to Dec 2023 | |
15,089 bbl/d | |
US$60.00/US$100.00 |
| |
WTI |
|
Collar |
| Jan 2024 to Mar 2024 | |
8,400 bbl/d | |
US$60.00/US$100.00 |
| |
WTI |
|
Collar |
| Apr 2024 to Jun 2024 | |
1,750 bbl/d | |
US$60.00/US$100.00 |
| |
WTI |
|
Collar |
| Jan 2024 to Jun 2024 | |
14,500 bbl/d | |
US$60.00/US$100.00 |
| |
WTI |
|
Collar (3) |
| Jan 2024 to Jun 2024 | |
2,500 bbl/d | |
US$60.00/US$90.00 |
| |
WTI |
|
|
| | |
| |
|
| |
|
|
Natural Gas |
| | |
| |
|
| |
|
|
|
| | |
| |
|
| |
HSC |
|
|
| | |
| |
Baytex pays: NYMEX |
| |
IFERC |
|
Basis differential (2) |
| July 2023 to Dec 2023 | |
11,413 mmbtu/d | |
Baytex receives: HSC less US$0.1525/mmbtu |
| |
FOM |
|
Fixed Sell |
| Oct 2023 to Mar 2024 | |
3,500 mmbtu/d | |
US$3.5025/mmbtu |
| |
NYMEX |
|
Collar |
| July 2023 to Dec 2023 | |
11,413 mmbtu/d | |
US$2.50/US$2.68 |
| |
NYMEX |
|
Collar |
| Jan 2024 to Mar 2024 | |
11,538 mmbtu/d | |
US$2.50/US$3.65 |
| |
NYMEX |
|
Collar |
| Apr 2024 to Jun 2024 | |
11,538 mmbtu/d | |
US$2.33/US$3.00 |
| |
NYMEX |
|
Collar |
| Jan 2024 to Dec 2024 | |
2,500 mmbtu/d | |
US$3.00/US$4.06 |
| |
NYMEX |
|
Collar |
| Jan 2024 to Dec 2024 | |
2,500 mmbtu/d | |
US$3.00/US$4.09 |
| |
NYMEX |
|
Collar |
| Jan 2024 to Dec 2024 | |
5,000 mmbtu/d | |
US$3.00/US$4.10 |
| |
NYMEX |
|
Collar |
| Jan 2024 to Dec 2024 | |
8,500 mmbtu/d | |
US$3.00/US$4.15 |
| |
NYMEX |
|
Collar |
| Jan 2024 to Dec 2024 | |
5,000 mmbtu/d | |
US$3.00/US$4.19 |
| |
NYMEX |
|
|
| | |
| |
|
| |
|
|
Natural Gas Liquids |
| | |
| |
|
| |
|
|
|
| | |
| |
|
| |
Mt. Belvieu |
|
|
| | |
| |
|
| |
Non-TET |
|
Fixed Sell |
| Jul 2023 to Mar 2024 | |
34,364 gallon/d | |
US$0.2280/gallon |
| |
Ethane |
|
| (1) | Based
on the weighted average price per unit for the period. |
| (2) | Contracts
that fix the basis differential between certain oil reference prices. |
| (3) | Contract
entered subsequent to June 30, 2023. |
| Baytex Energy Corp. Second Quarter Report 2023 | 23 |
OPERATING
NETBACK
The following table summarizes our operating netback on a per boe basis
for our Canadian and U.S. operations for the three and six months ended June 30, 2023 and 2022.
| |
Three Months Ended June 30 | |
| |
2023 | | |
2022 | |
($
per boe except for volume) | |
Canada | | |
U.S. | | |
Total | | |
Canada | | |
U.S. | | |
Total | |
Total production (boe/d) | |
| 55,874 | | |
| 33,887 | | |
| 89,761 | | |
| 54,919 | | |
| 28,170 | | |
| 83,090 | |
Operating netback: | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Total sales, net of blending and other expense (1) | |
$ | 66.34 | | |
$ | 67.60 | | |
$ | 66.82 | | |
$ | 104.91 | | |
$ | 106.48 | | |
$ | 105.44 | |
Less: | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Royalties (2) | |
| (9.30 | ) | |
| (19.66 | ) | |
| (13.21 | ) | |
| (18.24 | ) | |
| (31.37 | ) | |
| (22.69 | ) |
Operating expense (2) | |
| (17.97 | ) | |
| (9.11 | ) | |
| (14.62 | ) | |
| (16.50 | ) | |
| (9.73 | ) | |
| (14.21 | ) |
Transportation expense (2) | |
| (2.60 | ) | |
| (0.43 | ) | |
| (1.78 | ) | |
| (2.35 | ) | |
| — | | |
| (1.56 | ) |
Operating netback (1) | |
$ | 36.47 | | |
$ | 38.40 | | |
$ | 37.21 | | |
$ | 67.82 | | |
$ | 65.38 | | |
$ | 66.98 | |
Realized financial derivatives gain (loss) (3) | |
| — | | |
| — | | |
| 2.00 | | |
| — | | |
| — | | |
| (16.41 | ) |
Operating
netback after financial derivatives (1) | |
$ | 36.47 | | |
$ | 38.40 | | |
$ | 39.21 | | |
$ | 67.82 | | |
$ | 65.38 | | |
$ | 50.57 | |
| |
Six Months Ended June 30 | |
| |
2023 | | |
2022 | |
($
per boe except for volume) | |
Canada | | |
U.S. | | |
Total | | |
Canada | | |
U.S. | | |
Total | |
Total production (boe/d) | |
| 58,249 | | |
| 30,020 | | |
| 88,269 | | |
| 54,156 | | |
| 27,828 | | |
| 81,985 | |
Operating netback: | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Total sales, net of blending and other expense (1) | |
$ | 62.91 | | |
$ | 69.60 | | |
$ | 65.18 | | |
$ | 95.55 | | |
$ | 97.90 | | |
$ | 96.34 | |
Less: | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Royalties (2) | |
| (8.65 | ) | |
| (20.25 | ) | |
| (12.59 | ) | |
| (15.18 | ) | |
| (28.88 | ) | |
| (19.83 | ) |
Operating expense (2) | |
| (17.31 | ) | |
| (9.08 | ) | |
| (14.51 | ) | |
| (16.43 | ) | |
| (9.37 | ) | |
| (14.03 | ) |
Transportation expense (2) | |
| (2.87 | ) | |
| (0.25 | ) | |
| (1.98 | ) | |
| (2.14 | ) | |
| — | | |
| (1.41 | ) |
Operating netback (1) | |
$ | 34.08 | | |
$ | 40.02 | | |
$ | 36.10 | | |
$ | 61.80 | | |
$ | 59.65 | | |
$ | 61.07 | |
Realized financial derivatives gain (loss) (3) | |
| — | | |
| — | | |
| 1.36 | | |
| — | | |
| — | | |
| (14.04 | ) |
Operating
netback after financial derivatives (1) | |
$ | 34.08 | | |
$ | 40.02 | | |
$ | 37.46 | | |
$ | 61.80 | | |
$ | 59.65 | | |
$ | 47.03 | |
| (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 was $37.21/boe for Q2/2023
and $36.10/boe for YTD 2023 compared to $66.98/boe for Q2/2022 and $61.07/boe for YTD 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 and transportation expense of $16.40/boe for
Q2/2023 and $16.49/boe for YTD 2023 were higher than $15.77/boe for Q2/2022 and $15.44/boe for YTD 2022 due to inflation which resulted
in higher per boe operating and transportation costs. Operating netback including realized gains (losses) on financial derivatives was
$39.21/boe for Q2/2023 and $37.46/boe for YTD 2023 compared to $50.57/boe for Q2/2022 and $47.03/boe for YTD 2022.
GENERAL AND ADMINISTRATIVE EXPENSE
General and administrative ("G&A")
expense includes head office and corporate costs such as salaries and employee benefits, public company costs and administrative recoveries
earned for operating exploration and development activities on behalf of our working interest partners. G&A expense fluctuates with
head office staffing levels and the level of operated exploration and development activity during the period.
24 | Baytex Energy Corp. Second Quarter Report 2023 | |
The
following table summarizes our G&A expense for the three and six months ended June 30, 2023 and 2022.
| |
Three Months Ended June 30 | | |
Six Months Ended June 30 | |
($
thousands except for per boe) | |
2023 | | |
2022 | | |
Change | | |
2023 | | |
2022 | | |
Change | |
Gross general and administrative expense | |
$ | 16,476 | | |
$ | 12,223 | | |
$ | 4,253 | | |
$ | 30,893 | | |
$ | 25,729 | | |
$ | 5,164 | |
Overhead recoveries | |
| (1,236 | ) | |
| (583 | ) | |
| (653 | ) | |
| (3,919 | ) | |
| (2,407 | ) | |
| (1,512 | ) |
General and administrative expense | |
$ | 15,240 | | |
$ | 11,640 | | |
$ | 3,600 | | |
$ | 26,974 | | |
$ | 23,322 | | |
$ | 3,652 | |
General and administrative expense per boe (1) | |
$ | 1.87 | | |
$ | 1.54 | | |
$ | 0.33 | | |
$ | 1.69 | | |
$ | 1.57 | | |
$ | 0.12 | |
| (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 $15.2 million ($1.87/boe)
for Q2/2023 and $27.0 million ($1.69/boe) for YTD 2023 compared to $11.6 million ($1.54/boe) for Q2/2022 and $23.3 million ($1.57/boe)
for YTD 2022. G&A expense for Q2/2023 and YTD 2023 is consistent with expectations and was higher than the comparative periods of
2022 due to the increase in staffing levels and integration costs associated with the Merger with Ranger. G&A expense of $1.69/boe
during YTD 2023 is consistent with expectations and our annual guidance of $80 million ($1.80/boe) reflects the additional staffing levels
and administrative costs associated with the Merger with Ranger.
FINANCING AND INTEREST EXPENSE
Financing and interest expense includes interest
on our credit facilities, long-term notes and lease obligations as well as non-cash financing costs which include accretion on our debt
issue costs and asset retirement obligations. Financing and interest expense varies depending on debt levels outstanding during the period,
applicable borrowing rates, CAD/USD foreign exchange rates, along with the carrying amount of asset retirement obligations and the discount
rates used to present value these obligations.
The following table summarizes our financing and interest expense for
the three and six months ended June 30, 2023 and 2022.
| |
Three Months Ended June 30 | | |
Six Months Ended June 30 | |
($
thousands except for per boe) | |
2023 | | |
2022 | | |
Change | | |
2023 | | |
2022 | | |
Change | |
Interest on credit facilities | |
$ | 7,535 | | |
$ | 4,070 | | |
$ | 3,465 | | |
$ | 13,751 | | |
$ | 7,109 | | |
$ | 6,642 | |
Interest on long-term notes | |
| 20,565 | | |
| 16,356 | | |
| 4,209 | | |
| 32,659 | | |
| 33,700 | | |
| (1,041 | ) |
Interest on lease obligations | |
| 155 | | |
| 48 | | |
| 107 | | |
$ | 220 | | |
$ | 92 | | |
| 128 | |
Cash interest | |
$ | 28,255 | | |
$ | 20,474 | | |
$ | 7,781 | | |
$ | 46,630 | | |
$ | 40,901 | | |
$ | 5,729 | |
Accretion of debt issue costs | |
| 1,847 | | |
| 2,734 | | |
| (887 | ) | |
| 2,371 | | |
| 3,429 | | |
| (1,058 | ) |
Accretion of asset retirement obligations | |
| 4,395 | | |
| 3,869 | | |
| 526 | | |
| 9,221 | | |
| 6,991 | | |
| 2,230 | |
Financing and interest expense | |
$ | 34,497 | | |
$ | 27,077 | | |
$ | 7,420 | | |
$ | 58,222 | | |
$ | 51,321 | | |
$ | 6,901 | |
Cash interest per boe (1) | |
$ | 3.46 | | |
$ | 2.71 | | |
$ | 0.75 | | |
$ | 2.92 | | |
$ | 2.76 | | |
$ | 0.16 | |
Financing and interest expense per boe (1) | |
$ | 4.22 | | |
$ | 3.58 | | |
$ | 0.64 | | |
$ | 3.64 | | |
$ | 3.46 | | |
$ | 0.18 | |
| (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 $34.5 million
($4.22/boe) for Q2/2023 and $58.2 million ($3.64/boe) for YTD 2023 compared to $27.1 million ($3.58/boe) for Q2/2022 and $51.3 million
($3.46/boe) for YTD 2022. Higher interest costs in 2023 relative to 2022 reflects the additional debt outstanding as a result of the Merger
with Ranger in addition to an increase in interest rates.
Cash interest was $28.3 million ($3.46/boe) for
Q2/2023 and $46.6 million ($2.92/boe) for YTD 2023 compared to $20.5 million ($2.71/boe) for Q2/2022 and $40.9 million ($2.76/boe) for
YTD 2022. Cash interest was higher in both periods of 2023 relative to the same periods of 2022 which reflects the additional debt outstanding
due to the Merger with Ranger including the issuance of US$800.0 million aggregate principal amount of long-term notes. Interest on our
credit facilities in Q2/2023 and YTD 2023 was higher than the same periods of 2022 primarily due to the increase in benchmark borrowing
rate along with an increase in the principal amounts outstanding. The weighted average interest rate applicable to our credit facilities
was 6.8% for Q2/2023 and 6.5% for YTD 2023 which is higher than 2.6% for both Q2/2022 and YTD 2022.
Accretion of asset retirement obligations of $4.4
million for Q2/2023 and $9.2 million for YTD 2023 was higher than $3.9 million for Q2/2022 and $7.0 million for YTD 2022 due to a higher
discount rate used in both periods of 2023. Accretion of debt issue costs was lower in both periods of 2023 relative to the comparative
periods of 2022 due to lower debt issue costs outstanding for the majority of YTD 2023.
We have updated our cash interest annual guidance
for 2023 to $150 million ($3.38/boe) which reflects the incremental debt associated with the Merger with Ranger in addition to higher
interest rates on our credit facilities.
| Baytex Energy Corp. Second Quarter Report 2023 | 25 |
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 $0.4 million for Q2/2023 and $0.5 million for YTD 2023 compared to $7.2 million for Q2/2022 and $10.8 million for YTD 2022.
DEPLETION AND DEPRECIATION
Depletion and depreciation expense varies with
the carrying amount of the Company's oil and gas properties, the amount of proved plus probable reserves volumes and the rate of production
for the period. The following table summarizes depletion and depreciation expense for the three and six months ended June 30, 2023
and 2022.
| |
Three Months Ended June 30 | | |
Six Months Ended June 30 | |
($
thousands except for per boe) | |
2023 | | |
2022 | | |
Change | | |
2023 | | |
2022 | | |
Change | |
Depletion | |
$ | 174,473 | | |
$ | 140,809 | | |
$ | 33,664 | | |
$ | 338,908 | | |
$ | 280,255 | | |
$ | 58,653 | |
Depreciation | |
| 1,671 | | |
| 1,477 | | |
| 194 | | |
| 3,235 | | |
| 2,822 | | |
| 413 | |
Depletion and depreciation | |
$ | 176,144 | | |
$ | 142,286 | | |
$ | 33,858 | | |
$ | 342,143 | | |
$ | 283,077 | | |
$ | 59,066 | |
Depletion and depreciation per boe (1) | |
$ | 21.56 | | |
$ | 18.82 | | |
$ | 2.74 | | |
$ | 21.42 | | |
$ | 19.08 | | |
$ | 2.34 | |
| (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. |
Depletion and depreciation expense was $176.1
million ($21.56/boe) for Q2/2023 and $342.1 million ($21.42/boe) for YTD 2023 compared to $142.3 million ($18.82/boe) for Q2/2022 and
$283.1 million ($19.08/boe) for YTD 2022. Total depletion and depreciation expense and depletion and depreciation per boe were higher
in Q2/2023 and YTD 2023 relative to Q2/2022 and YTD 2022 as a result of the $245.2 million impairment reversal that was recorded at December 31,
2022 and an increase in future development costs attributed to proved plus probable reserves which resulted in a higher depletable base
for our oil and gas properties in 2023. Depletion expense for Q2/2023 and YTD 2023 also includes depletion on the oil and gas properties
acquired from Ranger subsequent to closing on June 20, 2023.
IMPAIRMENT
We did not identify indicators of impairment or impairment reversal
for any of our cash generating units ("CGUs") at June 30, 2023.
2022 Impairment Reversal
At December 31, 2022, we identified indicators
of impairment reversal for oil and gas properties in five of our six CGUs due to the increase in forecasted commodity prices in addition
to changes in proved plus probable reserves, which resulted in an impairment reversal of $245.2 million. 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.
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 along with the
share based compensation plan assumed from Ranger in June 2023. SBC expense associated with equity-settled 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 trade and other payables, and includes gains or losses on equity total return swaps. The liability is re-measured at each
reporting date and results in either a SBC expense or recovery based on changes in our share price.
We recorded SBC expense of $16.9 million for Q2/2023
and $26.7 million for YTD 2023 compared to $2.9 million for Q2/2022 and $6.9 million for YTD 2022. SBC expense for Q2/2023 and YTD 2023
includes $16.2 million of non-cash expense related to awards assumed and settled in Baytex common shares in conjunction with the Merger
with Ranger. 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.
26 | Baytex Energy Corp. Second Quarter Report 2023 | |
Cash
SBC expense of $0.7 million for Q2/2023 reflects a decline in our share price at June 30, 2023 compared to March 31, 2023 which
resulted in lower cash SBC expense compared to $2.6 million for Q2/2022 when we had a higher notional amount outstanding under the equity
total return swaps. 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. Cash SBC expense of $10.5 million for YTD 2023 was higher than $4.8 million for YTD 2022 as we applied a 1.5x performance
factor for 2022 results to performance awards during Q1/2023.
FOREIGN EXCHANGE
Unrealized foreign exchange gains and losses are
primarily a result of changes in the reported amount of our U.S. dollar denominated long-term notes and credit facilities in our Canadian
functional currency entities. The long-term notes and credit facilities are translated to Canadian dollars on the balance sheet date using
the closing CAD/USD exchange rate resulting in unrealized gains and losses. Realized foreign exchange gains and losses are due to day-to-day
U.S. dollar denominated transactions occurring in our Canadian functional currency entities.
| |
Three Months Ended June 30 | | |
Six Months Ended June 30 | |
($
thousands except for exchange rates) | |
2023 | |
|
2022 | | |
Change | | |
2023 | |
|
2022 | | |
Change | |
Unrealized foreign exchange (gain) loss | |
$ | (12,880 | ) |
|
$ | 27,499 | | |
$ | (40,379 | ) | |
$ | (13,093 | ) |
|
$ | 12,951 | | |
$ | (26,044 | ) |
Realized foreign exchange loss | |
| 941 | |
|
| 210 | | |
| 731 | | |
| 1,091 | |
|
| 413 | | |
| 678 | |
Foreign exchange (gain) loss | |
$ | (11,939 | ) |
|
$ | 27,709 | | |
$ | (39,648 | ) | |
$ | (12,002 | ) |
|
$ | 13,364 | | |
$ | (25,366 | ) |
CAD/USD exchange rates: | |
| | |
|
| | | |
| | | |
| | |
|
| | | |
| | |
At beginning of period | |
| 1.3528 | |
|
| 1.2484 | | |
| | | |
| 1.3534 | |
|
| 1.2656 | | |
| | |
At end of period | |
| 1.3238 | |
|
| 1.2872 | | |
| | | |
| 1.3238 | |
|
| 1.2872 | | |
| | |
We recorded a foreign exchange gain of $11.9 million
for Q2/2023 and $12.0 million for YTD 2023 compared to a loss of $27.7 million for Q2/2022 and $13.4 million for YTD 2022.
The unrealized foreign exchange gain of $12.9
million for Q2/2023 and $13.1 million for YTD 2023 is related to changes in the reported amount of our long-term notes and credit facilities
due to a strengthening of the Canadian dollar relative to the U.S. dollar at June 30, 2023 compared to March 31, 2023 and December 31,
2022. A weakening of the Canadian dollar relative to the U.S. dollar resulted in an unrealized foreign exchange loss for Q2/2022 and YTD
2022 related to changes in the reported amount of our long-term notes outstanding at June 30, 2022 compared to March 31, 2022
and December 31, 2021.
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 $0.9 million for Q2/2023 and $1.1 million for YTD 2023 compared to a loss of $0.2 million for Q2/2022
and $0.4 million for YTD 2022.
INCOME TAXES
| |
Three Months Ended June 30 | | |
Six Months Ended June 30 | |
($
thousands) | |
2023 | | |
2022 | | |
Change | | |
2023 | | |
2022 | | |
Change | |
Current income tax expense | |
$ | 1,350 | | |
$ | 1,140 | | |
$ | 210 | | |
$ | 2,470 | | |
$ | 2,050 | | |
$ | 420 | |
Deferred income tax (recovery) expense | |
| (178,360 | ) | |
| 39,920 | | |
| (218,280 | ) | |
| (162,837 | ) | |
| (27,412 | ) | |
| (135,425 | ) |
Total income tax (recovery) expense | |
$ | (177,010 | ) | |
$ | 41,060 | | |
$ | (218,070 | ) | |
$ | (160,367 | ) | |
$ | (25,362 | ) | |
$ | (135,005 | ) |
Current income tax expense was $1.4 million for
Q2/2023 and $2.5 million for YTD 2023 compared to $1.1 million for Q2/2022 and $2.1 million for YTD 2022.
We recorded deferred tax recovery of $178.4 million
for Q2/2023 and $162.8 million for YTD 2023 compared to expense of $39.9 million for Q2/2022 and a recovery $27.4 million for YTD 2022.
The deferred tax recovery in Q2/2023 and YTD 2023 is primarily related to the effects of the transaction restructuring for the Ranger
acquisition in Q2/2023 partially offset by income generated on our Canadian and U.S. operations for the period.
As disclosed in the 2022 annual financial statements,
certain indirect subsidiaries received reassessments from the Canada Revenue Agency (the "CRA”) in June 2016 that deny
$591.0 million of non-capital loss deductions relevant to the calculation of income taxes for the years 2011 through 2015. In September 2016,
we filed notices of objection with the CRA appealing each reassessment received. In mid-July 2023 we received a letter from the Appeals
Division of the CRA proposing to confirm the reassessments. We remain confident that our original tax filings are correct and intend to
defend these tax filings through the appeals process.
| Baytex Energy Corp. Second Quarter Report 2023 | 27 |
NET INCOME AND ADJUSTED FUNDS FLOW
The components of adjusted funds flow and net income or loss for the
three and six months ended June 30, 2023 and 2022 are set forth in the following table.
| |
Three Months Ended June 30 | | |
Six Months Ended June 30 | |
($
thousands) | |
2023 | | |
2022 | | |
Change | | |
2023 | | |
2022 | | |
Change | |
Petroleum and natural gas sales | |
$ | 598,760 | | |
$ | 854,169 | | |
$ | (255,409 | ) | |
$ | 1,154,096 | | |
$ | 1,527,994 | | |
$ | (373,898 | ) |
Royalties | |
| (107,920 | ) | |
| (171,559 | ) | |
| 63,639 | | |
| (201,173 | ) | |
| (294,279 | ) | |
| 93,106 | |
Revenue, net of royalties | |
| 490,840 | | |
| 682,610 | | |
| (191,770 | ) | |
| 952,923 | | |
| 1,233,715 | | |
| (280,792 | ) |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Expenses | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Operating | |
| (119,438 | ) | |
| (107,426 | ) | |
| (12,012 | ) | |
| (231,846 | ) | |
| (208,192 | ) | |
| (23,654 | ) |
Transportation | |
| (14,574 | ) | |
| (11,758 | ) | |
| (2,816 | ) | |
| (31,579 | ) | |
| (20,973 | ) | |
| (10,606 | ) |
Blending and other | |
| (52,995 | ) | |
| (56,895 | ) | |
| 3,900 | | |
| (112,676 | ) | |
| (98,335 | ) | |
| (14,341 | ) |
Operating netback (1) | |
$ | 303,833 | | |
$ | 506,531 | | |
$ | (202,698 | ) | |
$ | 576,822 | | |
$ | 906,215 | | |
$ | (329,393 | ) |
General and administrative | |
| (15,240 | ) | |
| (11,640 | ) | |
| (3,600 | ) | |
| (26,974 | ) | |
| (23,322 | ) | |
| (3,652 | ) |
Cash interest | |
| (28,255 | ) | |
| (20,474 | ) | |
| (7,781 | ) | |
| (46,630 | ) | |
| (40,901 | ) | |
| (5,729 | ) |
Realized financial derivatives loss (gain) | |
| 16,365 | | |
| (124,042 | ) | |
| 140,407 | | |
| 21,780 | | |
| (208,408 | ) | |
| 230,188 | |
Realized foreign exchange loss | |
| (941 | ) | |
| (210 | ) | |
| (731 | ) | |
| (1,091 | ) | |
| (413 | ) | |
| (678 | ) |
Other expense | |
| (141 | ) | |
| (751 | ) | |
| 610 | | |
| (354 | ) | |
| (1,001 | ) | |
| 647 | |
Current income tax expense | |
| (1,350 | ) | |
| (1,140 | ) | |
| (210 | ) | |
| (2,470 | ) | |
| (2,050 | ) | |
| (420 | ) |
Cash share-based compensation | |
| (681 | ) | |
| (2,570 | ) | |
| 1,889 | | |
| (10,504 | ) | |
| (4,809 | ) | |
| (5,695 | ) |
Adjusted funds flow (2) | |
$ | 273,590 | | |
$ | 345,704 | | |
$ | (72,114 | ) | |
$ | 510,579 | | |
$ | 625,311 | | |
$ | (114,732 | ) |
Transaction costs | |
| (32,832 | ) | |
| — | | |
| (32,832 | ) | |
| (41,703 | ) | |
| — | | |
| (41,703 | ) |
Exploration and evaluation | |
| (369 | ) | |
| (7,210 | ) | |
| 6,841 | | |
| (532 | ) | |
| (10,780 | ) | |
| 10,248 | |
Depletion and depreciation | |
| (176,144 | ) | |
| (142,286 | ) | |
| (33,858 | ) | |
| (342,143 | ) | |
| (283,077 | ) | |
| (59,066 | ) |
Non-cash share-based compensation | |
| (16,237 | ) | |
| (372 | ) | |
| (15,865 | ) | |
| (16,237 | ) | |
| (2,078 | ) | |
| (14,159 | ) |
Non-cash financing and accretion | |
| (6,242 | ) | |
| (6,603 | ) | |
| 361 | | |
| (11,592 | ) | |
| (10,420 | ) | |
| (1,172 | ) |
Non-cash other income | |
| — | | |
| 183 | | |
| (183 | ) | |
| 1,271 | | |
| 1,465 | | |
| (194 | ) |
Unrealized financial derivatives (loss) gain | |
| (19,403 | ) | |
| 58,768 | | |
| (78,171 | ) | |
| (10,193 | ) | |
| (97,493 | ) | |
| 87,300 | |
Unrealized foreign exchange gain (loss) | |
| 12,880 | | |
| (27,499 | ) | |
| 40,379 | | |
| 13,093 | | |
| (12,951 | ) | |
| 26,044 | |
Gain (loss) on dispositions | |
| — | | |
| 207 | | |
| (207 | ) | |
| (336 | ) | |
| 441 | | |
| (777 | ) |
Deferred income tax recovery (expense) | |
| 178,360 | | |
| (39,920 | ) | |
| 218,280 | | |
| 162,837 | | |
| 27,412 | | |
| 135,425 | |
Net income for the period | |
$ | 213,603 | | |
$ | 180,972 | | |
$ | 32,631 | | |
$ | 265,044 | | |
$ | 237,830 | | |
$ | 27,214 | |
| (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 $273.6 million
for Q2/2023 and $510.6 million for YTD 2023 compared to $345.7 million for Q2/2022 and $625.3 million for YTD 2022. The decrease in adjusted
funds flow was primarily due to lower operating netback which was $202.7 million lower in Q2/2023 and $329.4 million lower in YTD 2023
relative to the same periods of 2022 as a result of lower commodity prices that resulted in decreased revenue, net of royalties. The decrease
in operating netback was partially offset by realized gains on financial derivatives of $16.4 million for Q2/2023 and $21.8 million for
YTD 2023 which increased $140.4 million and $230.2 million relative to Q2/2022 and YTD 2022, respectively, when we recorded realized losses.
We reported net income of $213.6 million for Q2/2023 and $265.0 million for YTD 2023 compared to net income of $181.0 million reported
for Q2/2022 and $237.8 million for YTD 2022.
28 | Baytex Energy Corp. Second Quarter Report 2023 | |
OTHER
COMPREHENSIVE INCOME (LOSS)
Other comprehensive income or loss 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 $46.5 million for Q2/2023 and $47.0 million for YTD 2023 relates to the change in value of our U.S. net assets and
is due to the strengthening of the Canadian dollar relative to the U.S. dollar at June 30, 2023 compared to March 31, 2023 and
December 31, 2022. The CAD/USD exchange rate was 1.3238 CAD/ USD as at June 30, 2023 compared to 1.3528 CAD/USD at March 31,
2023 and 1.3534 CAD/USD at December 31, 2022.
CAPITAL EXPENDITURES
Capital expenditures for the three and six months ended June 30,
2023 and 2022 are summarized as follows.
| |
Three Months Ended June 30 | |
| |
2023 | | |
2022 | |
($
thousands) | |
Canada | | |
U.S. |
| |
Total | | |
Canada | | |
U.S. | | |
Total | |
Drilling, completion and equipping | |
$ | 77,518 | | |
$ | 69,309 |
| |
$ | 146,827 | | |
$ | 37,265 | | |
$ | 43,167 | | |
$ | 80,432 | |
Facilities | |
| 11,324 | | |
| 857 |
| |
| 12,181 | | |
| 6,912 | | |
| 1,414 | | |
| 8,326 | |
Land, seismic and other | |
| 7,561 | | |
| 4,135 |
| |
| 11,696 | | |
| 7,704 | | |
| 171 | | |
| 7,875 | |
Exploration and development expenditures | |
$ | 96,403 | | |
$ | 74,301 |
| |
$ | 170,704 | | |
$ | 51,881 | | |
$ | 44,752 | | |
$ | 96,633 | |
Property acquisitions | |
$ | (62 | ) | |
$ | — |
| |
$ | (62 | ) | |
$ | 208 | | |
$ | — | | |
$ | 208 | |
Proceeds from dispositions | |
$ | (50 | ) | |
$ | — |
| |
$ | (50 | ) | |
$ | (14 | ) | |
| | | |
$ | (14 | ) |
| |
Six Months Ended June 30 | |
| |
2023 | | |
2022 | |
($
thousands) | |
Canada | | |
U.S. | |
|
Total | | |
Canada | | |
U.S. | | |
Total | |
Drilling, completion and equipping | |
$ | 232,471 | | |
$ | 118,145 | |
|
$ | 350,616 | | |
$ | 144,263 | | |
$ | 70,305 | | |
$ | 214,568 | |
Facilities | |
| 28,309 | | |
| 857 | |
|
| 29,166 | | |
| 14,678 | | |
| 1,800 | | |
| 16,478 | |
Land, seismic and other | |
| 20,229 | | |
| 4,319 | |
|
| 24,548 | | |
| 19,070 | | |
| 339 | | |
| 19,409 | |
Exploration and development expenditures | |
$ | 281,009 | | |
$ | 123,321 | |
|
$ | 404,330 | | |
$ | 178,011 | | |
$ | 72,444 | | |
$ | 250,455 | |
Property acquisitions | |
$ | 444 | | |
$ | — | |
|
$ | 444 | | |
$ | 267 | | |
$ | — | | |
$ | 267 | |
Proceeds from dispositions | |
$ | (285 | ) | |
$ | — | |
|
$ | (285 | ) | |
$ | (41 | ) | |
$ | — | | |
$ | (41 | ) |
Exploration and development expenditures were
$170.7 million for Q2/2023 and $404.3 million for YTD 2023 compared to $96.6 million for Q2/2022 and $250.5 million for YTD 2022. Exploration
and development expenditures for Q2/2023 and YTD 2023 reflect increased development activity along with inflationary pressures that resulted
in higher costs related to the same periods of 2022 and expenditures for development activity that occurred on the properties acquired
from Ranger after the acquisition closed on June 20, 2023.
In Canada, exploration and development expenditures
were $96.4 million in Q2/2023 and $281.0 million in YTD 2023 compared to $51.9 million in Q2/2022 and $178.0 million in YTD 2022. Drilling
and completion spending of $77.5 million in Q2/2023 and $232.5 million in YTD 2023 reflects higher light and heavy oil development activity
relative to Q2/2022 and YTD 2022 when we spent $37.3 million and $144.3 million, respectively. We also invested $28.3 million on facilities
and $20.2 million on land, seismic and other expenditures during YTD 2023.
Total U.S. exploration and development expenditures
were $74.3 million for Q2/2023 and $123.3 million for YTD 2023 compared to $44.8 million in Q2/2022 and $72.4 million during YTD 2022.
Exploration and development activity for Q2/2023 and YTD 2023 includes $34.1 million of expenditures for development activity that occurred
on the properties acquired from Ranger after the acquisition closed on June 20, 2023 to June 30, 2023. Excluding the Ranger
acquisition, exploration and development expenditures in the U.S. were consistent for Q2/2023 and YTD 2023 and reflects slightly higher
costs due to inflation along with a weaker Canadian dollar relative to the same periods of 2022.
Our exploration and development expenditures for
YTD 2023 are consistent with expectations and we now expect full year expenditures of $1,005-$1,045 million for 2023 which reflects expenditures
on our operated Eagle Ford properties acquired from Ranger.
| Baytex Energy Corp. Second Quarter Report 2023 | 29 |
CAPITAL RESOURCES AND LIQUIDITY
Our objective for capital management is to maintain
a flexible capital structure and sufficient sources of liquidity to execute our capital programs, while meeting our short and long-term
commitments. We strive to actively manage our capital structure in response to changes in economic conditions. At June 30, 2023,
our capital structure was comprised of shareholders' capital, long-term notes, trade and other receivables, trade and other payables,
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.
The capital intensive nature of our operations
requires the maintenance of adequate sources of liquidity to fund ongoing exploration and development. Our capital resources consist primarily
of adjusted funds flow, available credit facilities and proceeds received from the divestiture of oil and gas properties.
Management of debt levels is a priority for us
in order to sustain operations and support our long-term plans. At June 30, 2023, net debt(1) was $2.8 billion compared
to $987.4 million at December 31, 2022. The increase in net debt 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 with Ranger. 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 and 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.
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.
Subsequent to Q2/2023 and through to July 26, 2023, we have spent $21.4 million to repurchase and cancel 4.7 million common shares.
On July 27, 2023, the Board of Directors has declared a quarterly cash dividend of CDN$0.0225 per share to be paid on October 2,
2023 for shareholders of record on September 15, 2023. 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.”
Credit Facilities
At June 30, 2023, the principal amount of
borrowings outstanding under our credit facilities was $986.9 million. Our credit facilities include US$1.1 billion of revolving credit
facilities (the "Revolving Facilities") and a US$150 million non-revolving term loan (the "Term Loan") (collectively,
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 Revolving Facilities were
increased to US$1.1 billion and mature on April 1, 2026. The Revolving 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 Term Loan is secured and matures on June 20,
2025. 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 are not borrowing base facilities
and do not require annual or semi-annual reviews. 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 Revolving 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.
Advances under the Term Loan can be drawn in U.S. funds and bear interest at the bank’s secured overnight financing rates ("SOFR")
plus applicable margins.
The weighted average interest rate on the Credit
Facilities was 6.8% for Q2/2023 and 6.5% for YTD 2023 compared to 2.8% and 2.6% for Q2/2022 and YTD 2022, respectively. The interest rate
on our Credit Facilities has increased with higher government benchmark rates in 2023 relative to 2022.
As at June 30, 2023, Baytex had $16.8 million
of outstanding letters of credit, $15.5 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.sedar.com.
| (1) | Capital
management measure. Refer to the Specified Financial Measures section in this MD&A for
further information. |
30 | Baytex Energy Corp. Second Quarter Report 2023 | |
Financial Covenants
The following table summarizes the financial covenants applicable to
the credit facilities and our compliance therewith at June 30, 2023.
| |
Position as at | | |
| | |
Covenant Description | |
June 30, 2023 | | |
Covenant | |
Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio) | |
| 0.5:1.0 | | |
| 3.5:1.0 | |
Interest Coverage (3) (Minimum Ratio) | |
| 13.3:1.0 | | |
| 3.5:1.0 | |
Total Debt (4) to Bank EBITDA (2) (Maximum Ratio) | |
| 1.2:1.0 | | |
| 4:0:1.0 | |
| (1) | "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 agreement. At June 30, 2023 our Senior Secured Debt was $986.9 million. |
| (2) | "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 June 30, 2023 was $2.1 billion. |
| (3) | "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 June 30, 2023 were $155.8 million. |
| (4) | "Total
Debt" is calculated in accordance with the credit facility agreement and is defined
as all obligations, liabilities, and indebtedness of Baytex excluding trade and other payables,
asset retirement obligations, leases, deferred income tax liabilities, and financial derivative
liabilities. At June 30, 2023 our Total Debt was $2.6 billion. |
Long-Term Notes
We have two issuances of long-term notes outstanding
with a total principal amount of $1.6 billion at June 30, 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 and will be redeemable at par from April 1, 2026 to maturity. At June 30, 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 Baytex also incurred transaction costs of $18.5
million in conjunction with the issuance.
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
six months ended June 30, 2023, we issued 5.9 million common shares pursuant to our share-based compensation programs and issued
311.4 million common shares on closing of the Merger with Ranger. As at June 30, 2023, we had 862.2 million common shares issued
and outstanding and no preferred shares issued and outstanding.
Subsequent to June 30, 2023 and through to
July 26, 2023, we repurchased 4.7 million common shares under our NCIB at an average price of $4.59 per share.
| Baytex Energy Corp. Second Quarter Report 2023 | 31 |
Contractual
Obligations
We have a number of financial obligations that
are incurred in the ordinary course of business. A significant portion of these obligations will be funded by adjusted funds flow. These
obligations as of June 30, 2023 and the expected timing for funding these obligations are noted in the table below.
| |
| | |
Less than | | |
| | |
| | |
| |
($ thousands) | |
Total | | |
1 year | | |
1-3 years | | |
3-5 years Beyond 5 years | |
Trade and other payables | |
$ | 616,608 | | |
$ | 614,763 | | |
$ | 1,845 | | |
$ | — | | |
$ | — | |
Financial derivatives | |
| 2,907 | | |
| 2,907 | | |
| — | | |
| — | | |
| — | |
Credit facilities – principal (1) | |
| 986,903 | | |
| — | | |
| 986,903 | | |
| — | | |
| — | |
Long-term notes – principal (1) | |
| 1,601,468 | | |
| — | | |
| — | | |
| 542,467 | | |
| 1,059,001 | |
Interest on long-term notes (2) | |
| 793,845 | | |
| 137,481 | | |
| 274,962 | | |
| 215,922 | | |
| 165,480 | |
Lease obligations – principal | |
| 42,191 | | |
| 20,297 | | |
| 8,722 | | |
| 7,095 | | |
| 6,077 | |
Processing agreements | |
| 5,812 | | |
| 810 | | |
| 1,022 | | |
| 640 | | |
| 3,340 | |
Transportation agreements | |
| 256,920 | | |
| 60,462 | | |
| 108,994 | | |
| 66,937 | | |
| 20,527 | |
Total | |
$ | 4,306,654 | | |
$ | 836,720 | | |
$ | 1,382,448 | | |
$ | 833,061 | | |
$ | 1,254,425 | |
| (1) | Principal
amount of instruments. |
| (2) | Excludes
interest on our credit facilities as interest payments fluctuate based on a floating rate
of interest and changes in the outstanding balances. |
We also have ongoing obligations related to the
abandonment and reclamation of well sites and facilities when they reach the end of their economic lives. Programs to abandon and reclaim
well sites and facilities are undertaken regularly in accordance with applicable legislative requirements.
32 | Baytex Energy Corp. Second Quarter Report 2023 | |
QUARTERLY
FINANCIAL INFORMATION
| |
2023 | | |
2022 | | |
2021 | |
($
thousands, except per common share amounts) | |
Q2 | | |
Q1 | | |
Q4 | | |
Q3 | | |
Q2 | | |
Q1 | | |
Q4 | | |
Q3 | |
Petroleum and natural
gas sales | |
| 598,760 | | |
| 555,336 | | |
| 648,986 | | |
| 712,065 | | |
| 854,169 | | |
| 673,825 | | |
| 552,403 | | |
| 488,736 | |
Net income (loss) | |
| 213,603 | | |
| 51,441 | | |
| 352,807 | | |
| 264,968 | | |
| 180,972 | | |
| 56,858 | | |
| 563,239 | | |
| 32,713 | |
Per common share – basic | |
| 0.37 | | |
| 0.09 | | |
| 0.65 | | |
| 0.48 | | |
| 0.32 | | |
| 0.10 | | |
| 1.00 | | |
| 0.06 | |
Per common share – diluted | |
| 0.36 | | |
| 0.09 | | |
| 0.64 | | |
| 0.47 | | |
| 0.32 | | |
| 0.10 | | |
| 0.98 | | |
| 0.06 | |
Adjusted
funds flow (1) | |
| 273,590 | | |
| 236,989 | | |
| 255,552 | | |
| 284,288 | | |
| 345,704 | | |
| 279,607 | | |
| 214,766 | | |
| 198,397 | |
Per common share – basic | |
| 0.47 | | |
| 0.43 | | |
| 0.47 | | |
| 0.51 | | |
| 0.61 | | |
| 0.49 | | |
| 0.38 | | |
| 0.35 | |
Per common share – diluted | |
| 0.47 | | |
| 0.43 | | |
| 0.46 | | |
| 0.51 | | |
| 0.60 | | |
| 0.49 | | |
| 0.37 | | |
| 0.35 | |
Free
cash flow (2) | |
| 96,313 | | |
| (1,918 | ) | |
| 143,324 | | |
| 111,568 | | |
| 245,316 | | |
| 121,318 | | |
| 137,133 | | |
| 101,215 | |
Per common share – basic | |
| 0.17 | | |
| — | | |
| 0.26 | | |
| 0.20 | | |
| 0.43 | | |
| 0.21 | | |
| 0.24 | | |
| 0.18 | |
Per common share – diluted | |
| 0.16 | | |
| — | | |
| 0.26 | | |
| 0.20 | | |
| 0.43 | | |
| 0.21 | | |
| 0.24 | | |
| 0.18 | |
Cash flows from operating activities | |
| 192,308 | | |
| 184,938 | | |
| 303,441 | | |
| 310,423 | | |
| 360,034 | | |
| 198,974 | | |
| 240,567 | | |
| 178,961 | |
Per common share – basic | |
| 0.33 | | |
| 0.34 | | |
| 0.56 | | |
| 0.56 | | |
| 0.63 | | |
| 0.35 | | |
| 0.43 | | |
| 0.32 | |
Per common share – diluted | |
| 0.33 | | |
| 0.34 | | |
| 0.55 | | |
| 0.56 | | |
| 0.63 | | |
| 0.35 | | |
| 0.42 | | |
| 0.31 | |
Exploration and development | |
| 170,704 | | |
| 233,626 | | |
| 103,634 | | |
| 167,453 | | |
| 96,633 | | |
| 153,822 | | |
| 73,995 | | |
| 94,235 | |
Canada | |
| 96,403 | | |
| 184,606 | | |
| 85,641 | | |
| 117,150 | | |
| 51,881 | | |
| 126,130 | | |
| 59,821 | | |
| 75,499 | |
U.S. | |
| 74,301 | | |
| 49,020 | | |
| 17,993 | | |
| 50,303 | | |
| 44,752 | | |
| 27,692 | | |
| 14,174 | | |
| 18,736 | |
Property acquisitions | |
| (62 | ) | |
| 506 | | |
| 1,085 | | |
| — | | |
| 208 | | |
| 59 | | |
| 1,443 | | |
| 89 | |
Proceeds from dispositions | |
| (50 | ) | |
| (235 | ) | |
| (148 | ) | |
| (25,460 | ) | |
| (14 | ) | |
| (27 | ) | |
| (6,857 | ) | |
| (701 | ) |
Net
debt (1) | |
| 2,814,844 | | |
| 995,170 | | |
| 987,446 | | |
| 1,113,559 | | |
| 1,123,297 | | |
| 1,275,680 | | |
| 1,409,717 | | |
| 1,564,658 | |
Total
assets (3) | |
| 8,617,444 | | |
| 5,180,059 | | |
| 5,103,769 | | |
| 4,923,617 | | |
| 4,870,432 | | |
| 4,917,811 | | |
| 4,834,643 | | |
| 4,453,971 | |
Common shares outstanding | |
| 862,192 | | |
| 545,553 | | |
| 544,930 | | |
| 547,615 | | |
| 560,139 | | |
| 569,214 | | |
| 564,213 | | |
| 564,213 | |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Daily production | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Total production (boe/d) | |
| 89,761 | | |
| 86,760 | | |
| 86,864 | | |
| 83,194 | | |
| 83,090 | | |
| 80,867 | | |
| 80,789 | | |
| 79,872 | |
Canada (boe/d) | |
| 55,874 | | |
| 60,651 | | |
| 56,946 | | |
| 55,803 | | |
| 54,919 | | |
| 53,385 | | |
| 50,362 | | |
| 48,124 | |
U.S. (boe/d) | |
| 33,887 | | |
| 26,109 | | |
| 29,918 | | |
| 27,391 | | |
| 28,170 | | |
| 27,482 | | |
| 30,428 | | |
| 31,748 | |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Benchmark prices | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
WTI oil (US$/bbl) | |
| 73.78 | | |
| 76.13 | | |
| 82.64 | | |
| 91.56 | | |
| 108.41 | | |
| 94.29 | | |
| 77.19 | | |
| 70.56 | |
WCS heavy oil ($/bbl) | |
| 78.85 | | |
| 69.44 | | |
| 77.37 | | |
| 93.62 | | |
| 122.05 | | |
| 100.99 | | |
| 78.82 | | |
| 71.81 | |
Edmonton par oil ($/bbl) | |
| 95.13 | | |
| 99.04 | | |
| 109.57 | | |
| 116.79 | | |
| 137.79 | | |
| 115.66 | | |
| 93.29 | | |
| 83.78 | |
CAD/USD avg exchange rate | |
| 1.3431 | | |
| 1.3520 | | |
| 1.3577 | | |
| 1.3059 | | |
| 1.2766 | | |
| 1.2661 | | |
| 1.2600 | | |
| 1.2601 | |
AECO natural gas ($/mcf) | |
| 2.35 | | |
| 4.34 | | |
| 5.58 | | |
| 5.81 | | |
| 6.27 | | |
| 4.59 | | |
| 4.94 | | |
| 3.54 | |
NYMEX natural gas (US$/mmbtu) | |
| 2.10 | | |
| 3.42 | | |
| 6.26 | | |
| 8.20 | | |
| 7.17 | | |
| 4.95 | | |
| 5.83 | | |
| 4.01 | |
Total sales, net of blending and
other | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
expense
($/boe) (2) | |
| 66.82 | | |
| 63.48 | | |
| 74.93 | | |
| 87.68 | | |
| 105.44 | | |
| 86.89 | | |
| 70.42 | | |
| 63.85 | |
Royalties
($/boe) (4) | |
| (13.21 | ) | |
| (11.94 | ) | |
| (15.23 | ) | |
| (19.21 | ) | |
| (22.69 | ) | |
| (16.86 | ) | |
| (13.47 | ) | |
| (12.32 | ) |
Operating
expense ($/boe) (4) | |
| (14.62 | ) | |
| (14.40 | ) | |
| (13.06 | ) | |
| (14.39 | ) | |
| (14.21 | ) | |
| (13.85 | ) | |
| (12.83 | ) | |
| (11.46 | ) |
Transportation
expense ($/boe) (4) | |
| (1.78 | ) | |
| (2.18 | ) | |
| (1.85 | ) | |
| (1.67 | ) | |
| (1.56 | ) | |
| (1.27 | ) | |
| (1.10 | ) | |
| (1.06 | ) |
Operating
netback ($/boe) (2) | |
| 37.21 | | |
| 34.96 | | |
| 44.79 | | |
| 52.41 | | |
| 66.98 | | |
| 54.91 | | |
| 43.02 | | |
| 39.01 | |
Financial
derivatives (loss) gain ($/boe) (4) | |
| 2.00 | | |
| 0.69 | | |
| (6.21 | ) | |
| (9.98 | ) | |
| (16.41 | ) | |
| (11.59 | ) | |
| (9.49 | ) | |
| (7.34 | ) |
Operating
netback after financial derivatives ($/boe) (2) | |
| 39.21 | | |
| 35.65 | | |
| 38.58 | | |
| 42.43 | | |
| 50.57 | | |
| 43.32 | | |
| 33.53 | | |
| 31.67 | |
| (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 expense, transportation expense or financial derivatives
gain or loss divided by barrels of oil equivalent production volume for the applicable period. |
| Baytex Energy Corp. Second Quarter Report 2023 | 33 |
Our
results for the previous eight quarters reflect the disciplined execution of our capital programs as oil and natural gas prices have strengthened.
Production of 89,761 boe/d for Q2/2023 has steadily increased from 79,872 boe/d in Q4/2020 which reflects strong well performance and
increased development activity as commodity prices have improved 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
and in our realized sales price of $105.44/boe for Q2/2022. Our realized price of $66.82/boe for Q2/2023 reflects recent declines in crude
oil prices caused by concern over future demand and economic slowdowns.
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
$273.6 million for Q2/2023 reflects strong price realizations and production results from our development plans in the U.S. and Canada
in addition to the Merger with Ranger.
Net debt can fluctuate on a quarterly basis depending
on the timing of exploration and development expenditures, acquisitions and dispositions, changes in our free cash 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 $1.6
billion at Q4/2020 to $2.8 billion at Q2/2023 is primarily a result of the Merger with Ranger which closed in Q2/2023 along with $159.0
million of shareholder returns. The change in net debt also reflects free cash flow(2) of $954.3 million 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. |
34 | Baytex Energy Corp. Second Quarter Report 2023 | |
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
AIF for the year ended December 31, 2022 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 the AIF for the year ended December 31, 2022, 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 development 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 June 30, 2023, nor are any such arrangements outstanding as of the
date of this MD&A.
CRITICAL ACCOUNTING ESTIMATES
There have been no changes in our critical accounting
estimates in the six months ended June 30, 2023 except for the critical accounting estimates related to the business combination
with Ranger. Further information on our critical accounting policies and estimates can be found in the notes to the audited annual consolidated
financial statements and MD&A for the year ended December 31, 2022.
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.
| Baytex Energy Corp. Second Quarter Report 2023 | 35 |
The
following table reconciles heavy oil, net of blending and other expense to amounts disclosed in the primary financial statements in the
following table.
| |
Three Months Ended June 30 | | |
Six Months Ended June 30 | |
($ thousands) | |
2023 | | |
2022 | | |
2023 | | |
2022 | |
Petroleum and natural gas sales | |
$ | 598,760 | | |
$ | 854,169 | | |
$ | 1,154,096 | | |
$ | 1,527,994 | |
Light oil and condensate (1) | |
| (308,810 | ) | |
| (415,592 | ) | |
| (597,275 | ) | |
| (776,567 | ) |
NGL (1) | |
| (20,163 | ) | |
| (33,183 | ) | |
| (41,997 | ) | |
| (62,674 | ) |
Natural gas sales (1) | |
| (18,338 | ) | |
| (59,293 | ) | |
| (46,290 | ) | |
| (98,214 | ) |
Heavy oil sales | |
$ | 251,449 | | |
$ | 346,101 | | |
$ | 468,534 | | |
$ | 590,539 | |
Blending and other expense (2) | |
| (52,995 | ) | |
| (56,895 | ) | |
| (112,676 | ) | |
| (98,335 | ) |
Heavy oil, net of blending and other expense | |
$ | 198,454 | | |
$ | 289,206 | | |
$ | 355,858 | | |
$ | 492,204 | |
| (1) | Component
of petroleum and natural gas sales. See Note 13 – Petroleum and Natural Gas Sales in
the consolidated financial statements for the three and six months ended June 30, 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.
The following table reconciles operating netback
and operating netback after realized financial derivatives to petroleum and natural gas sales.
| |
Three Months Ended June 30 | | |
Six Months Ended June 30 | |
($ thousands) | |
2023 | | |
2022 | | |
2023 | | |
2022 | |
Petroleum and natural gas sales | |
$ | 598,760 | | |
$ | 854,169 | | |
$ | 1,154,096 | | |
$ | 1,527,994 | |
Blending and other expense | |
| (52,995 | ) | |
| (56,895 | ) | |
| (112,676 | ) | |
| (98,335 | ) |
Total sales, net of blending and other expense | |
| 545,765 | | |
| 797,274 | | |
| 1,041,420 | | |
| 1,429,659 | |
Royalties | |
| (107,920 | ) | |
| (171,559 | ) | |
| (201,173 | ) | |
| (294,279 | ) |
Operating expense | |
| (119,438 | ) | |
| (107,426 | ) | |
| (231,846 | ) | |
| (208,192 | ) |
Transportation expense | |
| (14,574 | ) | |
| (11,758 | ) | |
| (31,579 | ) | |
| (20,973 | ) |
Operating netback | |
| 303,833 | | |
| 506,531 | | |
| 576,822 | | |
| 906,215 | |
Realized financial derivatives gain (loss) (1) | |
| 16,365 | | |
| (124,042 | ) | |
| 21,780 | | |
| (208,408 | ) |
Operating netback after realized financial derivatives | |
$ | 320,198 | | |
$ | 382,489 | | |
$ | 598,602 | | |
$ | 697,807 | |
| (1) | Realized financial derivatives
gain or loss is a component of financial derivatives gain or loss. See Note 17 - Financial
Instruments and Risk Management in the consolidated financial statements for the three and
six months ended June 30, 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, and transaction costs.
36 | Baytex Energy Corp. Second Quarter Report 2023 | |
Free
cash flow is reconciled to cash flows from operating activities in the following table.
| |
Three Months Ended June 30 | | |
Six Months Ended June 30 | |
($ thousands) | |
2023 | | |
2022 | | |
2023 | | |
2022 | |
Cash flows from operating activities | |
$ | 192,308 | | |
$ | 360,034 | | |
$ | 377,246 | | |
$ | 559,008 | |
Change in non-cash working capital | |
| 40,795 | | |
| (17,046 | ) | |
| 79,849 | | |
$ | 60,294 | |
Additions to exploration and evaluation assets | |
| (741 | ) | |
| (2,338 | ) | |
| (1,231 | ) | |
| (5,897 | ) |
Additions to oil and gas properties | |
| (169,963 | ) | |
| (94,295 | ) | |
| (403,099 | ) | |
| (244,558 | ) |
Payments on lease obligations | |
| (1,181 | ) | |
| (1,039 | ) | |
| (2,336 | ) | |
| (2,213 | ) |
Transaction costs | |
| 32,832 | | |
| — | | |
| 41,703 | | |
| — | |
Cash premiums on derivatives | |
| 2,263 | | |
| — | | |
| 2,263 | | |
| — | |
Free cash flow | |
$ | 96,313 | | |
$ | 245,316 | | |
$ | 94,395 | | |
$ | 366,634 | |
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.
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 define net debt to be the sum of our credit facilities and long-term notes
outstanding adjusted for unamortized debt issuance costs, trade and other payables, cash, and trade and other receivables. We also use
net debt projections to estimate future liquidity and whether additional sources of capital are required to fund ongoing operations.
| Baytex Energy Corp. Second Quarter Report 2023 | 37 |
The
following table summarizes our calculation of net debt. |
|
|
|
|
($ thousands) | |
June 30, 2023 | | |
December 31, 2022 | |
Credit facilities | |
$ | 964,332 | | |
$ | 383,031 | |
Unamortized debt issuance costs - Credit facilities (1) | |
| 22,571 | | |
| 2,363 | |
Long-term notes | |
| 1,563,897 | | |
| 547,598 | |
Unamortized debt issuance costs - Long-term notes (1) | |
| 37,571 | | |
| 6,999 | |
Trade and other payables | |
| 616,608 | | |
| 281,404 | |
Cash | |
| (19,637 | ) | |
| (5,464 | ) |
Trade and other receivables | |
| (370,498 | ) | |
| (228,485 | ) |
Net debt | |
$ | 2,814,844 | | |
$ | 987,446 | |
| (1) | Unamortized debt issuance
costs were obtained from Note 7 - Credit Facilities and Note 8 - Long-term Notes from the
consolidated financial statements for the three and six months ended June 30, 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 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 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.
| |
Three Months Ended June 30 | | |
Six Months Ended June 30 | |
($ thousands) | |
2023 | | |
2022 | | |
2023 | | |
2022 | |
Cash flow from operating activities | |
$ | 192,308 | | |
$ | 360,034 | | |
$ | 377,246 | | |
$ | 559,008 | |
Change in non-cash working capital | |
| 40,795 | | |
| (17,046 | ) | |
| 79,849 | | |
| 60,294 | |
Asset retirement obligations settled | |
| 5,392 | | |
| 2,716 | | |
| 9,518 | | |
| 6,009 | |
Transaction costs | |
| 32,832 | | |
| — | | |
| 41,703 | | |
| — | |
Cash premiums on derivatives | |
| 2,263 | | |
| — | | |
| 2,263 | | |
| — | |
Adjusted funds flow | |
$ | 273,590 | | |
$ | 345,704 | | |
$ | 510,579 | | |
$ | 625,311 | |
INTERNAL CONTROL OVER FINANCIAL REPORTING
We are required to comply with Multilateral Instrument
52-109 "Certification of Disclosure in Issuers' Annual and Interim Filings". This instrument requires us to disclose in our
interim MD&A any weaknesses in or changes to our internal control over financial reporting during the period that may have materially
affected, or are reasonably likely to materially affect, our internal controls over financial reporting. We confirm that no such weaknesses
were identified in, or changes were made to, internal controls over financial reporting during the three months ended June 30, 2023,
except for the matter described below.
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.
During the three months ended June 30, 2023,
the assets previously held by Ranger contributed revenues of $49.0 million (representing 8% of total revenues) and net income before tax
of $0.9 million (representing 3% of total net income before tax). At June 30, 2023, current assets of $178.4 million, non-current
assets of $3.3 billion, current liabilities of $321.7 million and non-current liabilities of $74.4 million were associated with the acquired
entity.
38 | Baytex Energy Corp. Second Quarter Report 2023 | |
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: expectations regarding our intention to further strengthen our balance sheet and the allocation
of free cash flow, including with respect to debt repayment and shareholder returns; our 2023 guidance on a stand-alone basis with respect
to exploration and development expenditures, average daily production, royalty rate and operating, transportation, general and administrative
and interest expenses; the existence, operation and strategy of our risk management program; that we expect to cash settle share awards;
the manner in which we fund our planned capital expenditures and monitor and manage our capital resources and liquidity; that we may
issue debt or equity securities, sell assets or adjust capital spending.
These forward-looking statements are based
on certain key assumptions regarding, among other things: petroleum and natural gas prices and differentials between light, medium and
heavy oil prices; well production rates and reserve volumes; our ability to add production and reserves through our exploration and development
activities; the future impact of wildfires on our production; that our core assets have more than 10 years development inventory at the
current pace of development; 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, including operating and transportation costs; interest and foreign exchange rates; the continuance of existing and, in certain
circumstances, proposed tax and royalty regimes; our hedging program; our ability to develop our crude oil and natural gas properties
in the manner currently contemplated; and current industry conditions, laws and regulations continuing in effect (or, where changes are
proposed, such changes being adopted as anticipated). Readers are cautioned that such assumptions, although considered reasonable by
Baytex at the time of preparation, may prove to be incorrect.
Actual results achieved will vary from the
information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include,
but are not limited to: risks relating to any unforeseen liabilities of Baytex; that Baytex fails to meet its guidance; the volatility
of oil and natural gas prices and price differentials (including the impacts of Covid-19); risks related to ongoing wildfires; restrictions
or costs imposed by climate change initiatives and the physical risks of climate change; risks associated with our ability to develop
our properties and add reserves; the impact of an energy transition on demand for petroleum productions; changes in income tax or other
laws or government incentive programs; availability and cost of gathering, processing and pipeline systems; retaining or replacing our
leadership and key personnel; the availability and cost of capital or borrowing; risks associated with a third-party operating our Eagle
Ford properties; risks associated with large projects; costs to develop and operate our properties, including transportation costs; public
perception and its influence on the regulatory regime; current or future control, legislation or regulations; new regulations on hydraulic
fracturing; restrictions on or access to water or other fluids; 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; additional risks associated with our thermal heavy oil projects; our ability
to compete with other organizations in the oil and gas industry; risks associated with our use of information technology systems; 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 of counterparty default; the impact of Indigenous claims; risks associated with expansion into new activities;
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, 2022, filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange
Commission and in our other public filings.
The above summary of assumptions and risks
related to forward-looking statements has been provided in order to provide shareholders and potential investors with a more complete
perspective on Baytex’s current and future operations and such information may not be appropriate for other purposes.
There is no representation by Baytex that
actual results achieved will be the same in whole or in part as those referenced in the forward-looking statements and Baytex does not
undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information,
future events or otherwise, except as may be required by applicable securities law.
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.
| Baytex Energy Corp. Second Quarter Report 2023 | 39 |
Baytex Energy Corp.
Condensed Consolidated Interim Statements of Financial Position
(thousands of Canadian dollars) (unaudited)
| |
|
|
|
|
As at | |
| |
Notes | | |
June 30, 2023 | | |
December 31, 2022 | |
ASSETS | |
| | | |
| | | |
| | |
Current assets | |
| | | |
| | | |
| | |
Cash | |
| | | |
$ | 19,637 | | |
$ | 5,464 | |
Trade and other receivables | |
| | | |
| 370,498 | | |
| 228,485 | |
Financial derivatives | |
| 17 | | |
| 27,505 | | |
| 10,105 | |
| |
| | | |
| 417,640 | | |
| 244,054 | |
Non-current assets | |
| | | |
| | | |
| | |
Exploration and evaluation assets | |
| 5 | | |
| 162,448 | | |
| 168,684 | |
Oil and gas properties | |
| 6 | | |
| 7,759,725 | | |
| 4,620,766 | |
Other plant and equipment | |
| | | |
| 6,794 | | |
| 6,568 | |
Lease assets | |
| | | |
| 35,979 | | |
| 6,453 | |
Deferred income tax asset | |
| 14 | | |
| 234,858 | | |
| 57,244 | |
| |
| | | |
$ | 8,617,444 | | |
$ | 5,103,769 | |
LIABILITIES | |
| | | |
| | | |
| | |
Current liabilities | |
| | | |
| | | |
| | |
Trade and other payables | |
| | | |
$ | 614,763 | | |
$ | 272,195 | |
Financial derivatives | |
| 17 | | |
| 2,907 | | |
| — | |
Lease obligations | |
| | | |
| 24,289 | | |
| 3,521 | |
Asset retirement obligations | |
| 9 | | |
| 12,965 | | |
| 12,813 | |
| |
| | | |
| 654,924 | | |
| 288,529 | |
Non-current liabilities | |
| | | |
| | | |
| | |
Trade and other payables | |
| | | |
| 1,845 | | |
| 9,209 | |
Credit facilities | |
| 7 | | |
| 964,332 | | |
| 383,031 | |
Long-term notes | |
| 8 | | |
| 1,563,897 | | |
| 547,598 | |
Lease obligations | |
| | | |
| 11,879 | | |
| 3,017 | |
Asset retirement obligations | |
| 9 | | |
| 641,605 | | |
| 576,110 | |
Deferred income tax liability | |
| 14 | | |
| 177,751 | | |
| 265,858 | |
| |
| | | |
| 4,016,233 | | |
| 2,073,352 | |
SHAREHOLDERS’ EQUITY | |
| | | |
| | | |
| | |
Shareholders' capital | |
| 10 | | |
| 6,852,328 | | |
| 5,499,664 | |
Contributed surplus | |
| | | |
| 89,970 | | |
| 89,879 | |
Accumulated other comprehensive income | |
| | | |
| 709,190 | | |
| 756,195 | |
Deficit | |
| | | |
| (3,050,277 | ) | |
| (3,315,321 | ) |
| |
| | | |
| 4,601,211 | | |
| 3,030,417 | |
| |
| | | |
$ | 8,617,444 | | |
$ | 5,103,769 | |
Subsequent events (note 10 and note 17)
See accompanying notes to the condensed consolidated interim financial
statements.
40 | Baytex Energy Corp. Second Quarter Report 2023 | |
Baytex Energy Corp.
Condensed Consolidated Interim Statements of Income and Comprehensive
Income
(thousands of Canadian dollars, except per common share amounts
and weighted average common shares) (unaudited)
| |
| | |
Three Months Ended June 30 | | |
Six Months Ended June 30 | |
| |
Notes | | |
2023 | | |
2022 | | |
2023 | | |
2022 | |
Revenue, net of royalties | |
| | | |
| | | |
| | | |
| | | |
| | |
Petroleum and natural gas sales | |
| 13 | | |
$ | 598,760 | | |
$ | 854,169 | | |
$ | 1,154,096 | | |
$ | 1,527,994 | |
Royalties | |
| | | |
| (107,920 | ) | |
| (171,559 | ) | |
| (201,173 | ) | |
| (294,279 | ) |
| |
| | | |
| 490,840 | | |
| 682,610 | | |
| 952,923 | | |
| 1,233,715 | |
Expenses | |
| | | |
| | | |
| | | |
| | | |
| | |
Operating | |
| | | |
| 119,438 | | |
| 107,426 | | |
| 231,846 | | |
| 208,192 | |
Transportation | |
| | | |
| 14,574 | | |
| 11,758 | | |
| 31,579 | | |
| 20,973 | |
Blending and other | |
| | | |
| 52,995 | | |
| 56,895 | | |
| 112,676 | | |
| 98,335 | |
General and administrative | |
| | | |
| 15,240 | | |
| 11,640 | | |
| 26,974 | | |
| 23,322 | |
Transaction costs | |
| 3 | | |
| 32,832 | | |
| — | | |
| 41,703 | | |
| — | |
Exploration and evaluation | |
| 5 | | |
| 369 | | |
| 7,210 | | |
| 532 | | |
| 10,780 | |
Depletion and depreciation | |
| | | |
| 176,144 | | |
| 142,286 | | |
| 342,143 | | |
| 283,077 | |
Share-based compensation | |
| 11 | | |
| 16,918 | | |
| 2,942 | | |
| 26,741 | | |
| 6,887 | |
Financing and interest | |
| 15 | | |
| 34,497 | | |
| 27,077 | | |
| 58,222 | | |
| 51,321 | |
Financial derivatives (gain) loss | |
| 17 | | |
| 3,038 | | |
| 65,274 | | |
| (11,587 | ) | |
| 305,901 | |
Foreign exchange (gain) loss | |
| 16 | | |
| (11,939 | ) | |
| 27,709 | | |
| (12,002 | ) | |
| 13,364 | |
(Gain) loss on dispositions | |
| | | |
| — | | |
| (207 | ) | |
| 336 | | |
| (441 | ) |
Other expense (income) | |
| | | |
| 141 | | |
| 568 | | |
| (917 | ) | |
| (464 | ) |
| |
| | | |
| 454,247 | | |
| 460,578 | | |
| 848,246 | | |
| 1,021,247 | |
Net income before income taxes | |
| | | |
| 36,593 | | |
| 222,032 | | |
| 104,677 | | |
| 212,468 | |
Income tax expense (recovery) | |
| 14 | | |
| | | |
| | | |
| | | |
| | |
Current income tax expense | |
| | | |
| 1,350 | | |
| 1,140 | | |
| 2,470 | | |
| 2,050 | |
Deferred income tax expense (recovery) | |
| | | |
| (178,360 | ) | |
| 39,920 | | |
| (162,837 | ) | |
| (27,412 | ) |
| |
| | | |
| (177,010 | ) | |
| 41,060 | | |
| (160,367 | ) | |
| (25,362 | ) |
Net income | |
| | | |
$ | 213,603 | | |
$ | 180,972 | | |
$ | 265,044 | | |
$ | 237,830 | |
Other comprehensive income (loss) | |
| | | |
| | | |
| | | |
| | | |
| | |
Foreign currency translation
adjustment | |
| | | |
| (46,457 | ) | |
| 58,917 | | |
| (47,005 | ) | |
| 30,838 | |
Comprehensive income | |
| | | |
$ | 167,146 | | |
$ | 239,889 | | |
$ | 218,039 | | |
$ | 268,668 | |
| |
| | | |
| | | |
| | | |
| | | |
| | |
Net income per common share | |
| 12 | | |
| | | |
| | | |
| | | |
| | |
Basic | |
| | | |
$ | 0.37 | | |
$ | 0.32 | | |
$ | 0.47 | | |
$ | 0.42 | |
Diluted | |
| | | |
$ | 0.36 | | |
$ | 0.32 | | |
$ | 0.47 | | |
$ | 0.42 | |
| |
| | | |
| | | |
| | | |
| | | |
| | |
Weighted average common shares (000's) | |
| 12 | | |
| | | |
| | | |
| | | |
| | |
Basic | |
| | | |
| 583,365 | | |
| 566,997 | | |
| 564,319 | | |
| 566,262 | |
Diluted | |
| | | |
| 588,170 | | |
| 571,697 | | |
| 569,284 | | |
| 570,844 | |
See accompanying notes to the condensed consolidated interim financial
statements.
| Baytex Energy Corp. Second Quarter Report 2023 | 41 |
Baytex Energy Corp.
Condensed Consolidated Interim Statements of Changes in Equity
(thousands of Canadian dollars) (unaudited)
| |
| | |
| | |
| | |
Accumulated | | |
| | |
| |
| |
| | |
| | |
| | |
other | | |
| | |
| |
| |
| | |
Shareholders’ | | |
Contributed | | |
comprehensive | | |
| | |
| |
| |
Notes | | |
capital | | |
surplus | | |
income (loss) | | |
Deficit | | |
Total equity | |
Balance at December 31, 2021 | |
| | | |
$ | 5,736,593 | | |
$ | 13,559 | | |
$ | 632,103 | | |
$ | (4,170,926 | ) | |
$ | 2,211,329 | |
Vesting of share awards | |
| | | |
| 8,429 | | |
| (8,429 | ) | |
| — | | |
| — | | |
| — | |
Share-based compensation | |
| | | |
| — | | |
| 2,078 | | |
| — | | |
| — | | |
| 2,078 | |
Repurchase of common shares for cancellation | |
| | | |
| (91,139 | ) | |
| 28,675 | | |
| — | | |
| — | | |
| (62,464 | ) |
Comprehensive income | |
| | | |
| — | | |
| — | | |
| 30,838 | | |
| 237,830 | | |
| 268,668 | |
Balance at June 30, 2022 | |
| | | |
$ | 5,653,883 | | |
$ | 35,883 | | |
$ | 662,941 | | |
$ | (3,933,096 | ) | |
$ | 2,419,611 | |
Balance at December 31, 2022 | |
| | | |
$ | 5,499,664 | | |
$ | 89,879 | | |
$ | 756,195 | | |
$ | (3,315,321 | ) | |
$ | 3,030,417 | |
Issued on corporate acquisition | |
| 3 | | |
| 1,326,435 | | |
| 21,316 | | |
| — | | |
| — | | |
| 1,347,751 | |
Vesting of share awards | |
| 10 | | |
| 26,229 | | |
| (37,462 | ) | |
| — | | |
| — | | |
| (11,233 | ) |
Share-based compensation | |
| 11 | | |
| — | | |
| 16,237 | | |
| — | | |
| — | | |
| 16,237 | |
Comprehensive (loss) income | |
| | | |
| — | | |
| — | | |
| (47,005 | ) | |
| 265,044 | | |
| 218,039 | |
Balance at June 30, 2023 | |
| | | |
$ | 6,852,328 | | |
$ | 89,970 | | |
$ | 709,190 | | |
$ | (3,050,277 | ) | |
$ | 4,601,211 | |
See accompanying notes to the condensed consolidated interim financial
statements.
42 | Baytex Energy Corp. Second Quarter Report 2023 | |
Baytex Energy Corp.
Condensed Consolidated Interim Statements of Cash Flows
(thousands of Canadian dollars) (unaudited)
| |
| | |
Three
Months Ended June 30 | | |
Six
Months Ended June 30 | |
| |
Notes | | |
2023 | | |
2022 | | |
2023 | | |
2022 | |
CASH
PROVIDED BY (USED IN): | |
| | | |
| | | |
| | | |
| | | |
| | |
Operating
activities | |
| | | |
| | | |
| | | |
| | | |
| | |
Net
income | |
| | | |
$ | 213,603 | | |
$ | 180,972 | | |
$ | 265,044 | | |
$ | 237,830 | |
Adjustments
for: | |
| | | |
| | | |
| | | |
| | | |
| | |
Non-cash
share-based compensation | |
| 11 | | |
| 16,237 | | |
| 372 | | |
| 16,237 | | |
| 2,078 | |
Unrealized
foreign exchange (gain) loss | |
| 16 | | |
| (12,880 | ) | |
| 27,499 | | |
| (13,093 | ) | |
| 12,951 | |
Exploration
and evaluation | |
| 5 | | |
| 369 | | |
| 7,210 | | |
| 532 | | |
| 10,780 | |
Depletion
and depreciation | |
| | | |
| 176,144 | | |
| 142,286 | | |
| 342,143 | | |
| 283,077 | |
Non-cash
financing and accretion | |
| 15 | | |
| 6,242 | | |
| 6,603 | | |
| 11,592 | | |
| 10,420 | |
Non-cash
other income | |
| 9 | | |
| — | | |
| (183 | ) | |
| (1,271 | ) | |
| (1,465 | ) |
Unrealized
financial derivatives (gain) loss | |
| 17 | | |
| 19,403 | | |
| (58,768 | ) | |
| 10,193 | | |
| 97,493 | |
Cash
premiums on derivatives | |
| | | |
| (2,263 | ) | |
| — | | |
| (2,263 | ) | |
| — | |
(Gain)
loss on dispositions | |
| | | |
| — | | |
| (207 | ) | |
| 336 | | |
| (441 | ) |
Deferred
income tax expense (recovery) | |
| 14 | | |
| (178,360 | ) | |
| 39,920 | | |
| (162,837 | ) | |
| (27,412 | ) |
Asset
retirement obligations settled | |
| 9 | | |
| (5,392 | ) | |
| (2,716 | ) | |
| (9,518 | ) | |
| (6,009 | ) |
Change
in non-cash working capital | |
| | | |
| (40,795 | ) | |
| 17,046 | | |
| (79,849 | ) | |
| (60,294 | ) |
| |
| | | |
| 192,308 | | |
| 360,034 | | |
| 377,246 | | |
| 559,008 | |
Financing
activities | |
| | | |
| | | |
| | | |
| | | |
| | |
Increase
(decrease) in credit facilities | |
| | | |
| 577,428 | | |
| 62,791 | | |
| 601,979 | | |
| (15,351 | ) |
Decrease
in acquired credit facilities | |
| 3 | | |
| (373,608 | ) | |
| — | | |
| (373,608 | ) | |
| — | |
Debt issuance
costs | |
| | | |
| (39,925 | ) | |
| (1,832 | ) | |
| (39,925 | ) | |
| (1,832 | ) |
Payments
on lease obligations | |
| | | |
| (1,181 | ) | |
| (1,039 | ) | |
| (2,336 | ) | |
| (2,213 | ) |
Net proceeds
from issuance of long-term notes | |
| 8 | | |
| 1,046,197 | | |
| — | | |
| 1,046,197 | | |
| — | |
Redemption
of long-term notes | |
| 8 | | |
| — | | |
| (252,830 | ) | |
| — | | |
| (252,830 | ) |
Redemption
of acquired long-term notes | |
| 3 | | |
| (569,256 | ) | |
| — | | |
| (569,256 | ) | |
| — | |
Repurchase
of common shares | |
| 10 | | |
| — | | |
| (62,464 | ) | |
| — | | |
| (62,464 | ) |
| |
| | | |
| 639,655 | | |
| (255,374 | ) | |
| 663,051 | | |
| (334,690 | ) |
Investing
activities | |
| | | |
| | | |
| | | |
| | | |
| | |
Additions
to exploration and evaluation assets | |
| 5 | | |
| (741 | ) | |
| (2,338 | ) | |
| (1,231 | ) | |
| (5,897 | ) |
Additions
to oil and gas properties | |
| 6 | | |
| (169,963 | ) | |
| (94,295 | ) | |
| (403,099 | ) | |
| (244,558 | ) |
Additions
to other plant and equipment | |
| | | |
| (580 | ) | |
| (260 | ) | |
| (1,021 | ) | |
| (634 | ) |
Corporate
acquisition, net of cash acquired | |
| 3 | | |
| (662,579 | ) | |
| | | |
| (662,579 | ) | |
| | |
Property
acquisitions | |
| | | |
| 62 | | |
| (208 | ) | |
| (444 | ) | |
| (267 | ) |
Proceeds
from dispositions | |
| | | |
| 50 | | |
| 14 | | |
| 285 | | |
| 41 | |
Change
in non-cash working capital | |
| | | |
| 14,980 | | |
| (7,573 | ) | |
| 41,965 | | |
| 26,997 | |
| |
| | | |
| (818,771 | ) | |
| (104,660 | ) | |
| (1,026,124 | ) | |
| (224,318 | ) |
Change in
cash | |
| | | |
| 13,192 | | |
| — | | |
| 14,173 | | |
| — | |
Cash,
beginning of period | |
| | | |
| 6,445 | | |
| — | | |
| 5,464 | | |
| — | |
Cash,
end of period | |
| | | |
$ | 19,637 | | |
$ | — | | |
$ | 19,637 | | |
$ | — | |
| |
| | | |
| | | |
| | | |
| | | |
| | |
Supplementary
information | |
| | | |
| | | |
| | | |
| | | |
| | |
Interest
paid | |
| | | |
$ | 7,535 | | |
$ | 11,181 | | |
$ | 38,004 | | |
$ | 41,529 | |
Income
taxes paid | |
| | | |
$ | 3,603 | | |
$ | 263 | | |
$ | 3,603 | | |
$ | 263 | |
See accompanying notes to the condensed consolidated interim financial
statements.
| Baytex Energy Corp. Second Quarter Report 2023 | 43 |
Baytex Energy Corp.
Notes to the Condensed Consolidated Interim Financial Statements
For the periods ended June 30, 2023 and 2022
(all tabular
amounts in thousands of Canadian dollars, except per common share amounts) (unaudited)
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 the state of Texas in the United States. The Company’s common shares are traded on the Toronto Stock
Exchange and the New York Stock Exchange under the symbol BTE. The Company’s head and principal office is located at 2800, 520 –
3rd Avenue S.W., Calgary, Alberta, T2P 0R3, and its registered office is located at 2400, 525 – 8th Avenue S.W., Calgary, Alberta,
T2P 1G1.
2. BASIS
OF PRESENTATION
The condensed consolidated interim financial statements
("consolidated financial statements") have been prepared in accordance with International Accounting Standards 34, Interim
Financial Reporting, under International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards
Board (the "IASB"). These condensed consolidated financial statements do not include all the necessary annual disclosures as
prescribed by IFRS and should be read in conjunction with the annual consolidated financial statements as at and for the year ended December 31,
2022.
The consolidated financial statements were approved by the Board of
Directors of Baytex on July 27, 2023.
The consolidated financial statements have been
prepared on a historical cost basis, with the exception of derivative financial instruments which have been measured at fair value. 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 when otherwise indicated.
The audited consolidated financial statements
of the Company as at and for the year ended December 31, 2022 are available through its filings on SEDAR at www.sedar.com and through
the U.S. Securities and Exchange Commission at www.sec.gov.
Estimation Uncertainty
Management makes judgements and assumptions about
the future in deriving estimates used in preparation of these consolidated financial statements in accordance with IFRS. Sources of estimation
uncertainty include estimates used to determine economically recoverable oil, natural gas, and natural gas liquids reserves, the recoverable
amount of long-lived assets or cash generating units, the 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. There have been no changes in our key areas of
judgement or estimation uncertainty for the six months ended June 30, 2023 except for the judgements and estimates related to Business
Combinations as discussed below.
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. Oil and gas properties acquired represents the largest fair value estimate which is derived from the present
value of expected future cash flows after-tax using estimates of reserves acquired prepared by an independent qualified reserve evaluator
using forecasted commodity prices and applying a discount rate. Assumptions used to arrive at the fair value are further verified by way
of market comparisons and third party sources.
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 two IFRS Sustainability Disclosure Standards 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.
Significant Accounting Policies
The accounting policies, critical accounting judgments
(with the addition of Business Combinations) and significant estimates used in these consolidated financial statements are consistent
with those used in the preparation of the 2022 annual financial statements.
44 | Baytex Energy Corp. Second Quarter Report 2023 | |
3. BUSINESS
COMBINATION
On June 20, 2023, Baytex closed the previously
announced acquisition whereby Baytex acquired, directly and indirectly, all of the issued and outstanding common shares of Ranger Oil
Corporation (“Ranger”), a publicly traded oil and gas exploration and production company with operations in the Eagle Ford.
Baytex 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 whereby the net assets acquired and liabilities assumed were recorded at fair value at the acquisition date. The total consideration
paid by Baytex was US$1.6 billion (C$2.1 billion) consisting of $732.8 million in cash consideration and the issuance of 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 based on estimates of proved and probable oil and gas reserves and the associated cash flows. Factors that impact these cash flows
include production volumes, royalty obligations, operating costs, capital costs, tax rates, forecasted commodity prices, along with inflation
and discount rates used to estimate present value. These calculations require the use of estimates and assumptions including cash flows
associated with proved plus probable oil and gas reserves, the discount rate used to present value future cash flows, and assumptions
regarding the timing and amount of capital expenditures and future abandonment and reclamation obligations. Any changes to these estimates
and assumptions could impact the calculation of the recoverable amount and the carrying value of assets. The fair value of oil and gas
properties were determined using a discount rate of 12.5%.
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 credit-adjusted discount rate of 9%.
The total consideration paid and estimates of the fair value of the
assets acquired and liabilities assumed as at the date of the acquisition are set forth in the table below. The preliminary purchase price
allocation 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 | |
$ | 553,150 | | |
$ | 732,840 | |
Common shares issued | |
| 1,001,196 | | |
| 1,326,435 | |
Share based compensation (2) | |
| 20,107 | | |
| 26,638 | |
Total consideration | |
$ | 1,574,453 | | |
$ | 2,085,913 | |
| |
| | | |
| | |
Fair value of net assets acquired | |
| | | |
| | |
Oil and gas properties | |
$ | 2,325,996 | | |
$ | 3,081,596 | |
Working capital deficiency excluding bank debt and financial derivatives (3) | |
| (108,147 | ) | |
| (143,278 | ) |
Financial derivatives | |
| 17,030 | | |
| 22,562 | |
Lease assets | |
| 15,708 | | |
| 20,811 | |
Lease obligations | |
| (15,708 | ) | |
| (20,811 | ) |
Credit facilities | |
| (282,000 | ) | |
| (373,608 | ) |
Long-term notes | |
| (429,676 | ) | |
| (569,256 | ) |
Asset retirement obligations | |
| (23,632 | ) | |
| (31,310 | ) |
Deferred income tax asset | |
| 74,882 | | |
| 99,207 | |
Net assets acquired | |
$ | 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) | Follow 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 11). |
| (3) | Includes $70.3 million (US$53.0
million) of cash. Accounts receivable acquired is net of a provision for expected credit
losses of approximately $0.3 million. |
| Baytex Energy Corp. Second Quarter Report 2023 | 45 |
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 three months ended
June 30, 2023, the acquisition contributed revenues and net income before tax of $49.0 million and $0.9 million respectively. Had
the acquisition occurred on January 1, 2023, revenues and net income before income taxes would have increased by $848.4 million and
$218.3 million, respectively, for the six months ended June 30, 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 six months ended June 30, 2023,
Baytex incurred $41.7 million of transaction costs, including consulting, financial advisory, legal and filing fees related to the acquisition
of Ranger.
4. SEGMENTED
FINANCIAL INFORMATION
Baytex's reportable segments are determined based on the geographic
location and nature of the underlying operations:
| · | Canada includes the exploration for, and the development and production of, crude oil and natural gas
in Western Canada; |
| · | U.S. includes the exploration for, and the development and production of, crude oil and natural gas in
the Eagle Ford in Texas; and |
| · | Corporate includes corporate activities and items not allocated between operating segments. |
| |
Canada | | |
U.S. | | |
Corporate | | |
Consolidated | |
Three Months Ended June 30 | |
2023 | | |
2022 | | |
2023 | | |
2022 | | |
2023 | | |
2022 | | |
2023 | | |
2022 | |
Revenue, net of royalties | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Petroleum and natural gas sales | |
$ | 390,292 | | |
$ | 581,197 | | |
$ | 208,468 | | |
$ | 272,972 | | |
$ | — | | |
$ | — | | |
$ | 598,760 | | |
$ | 854,169 | |
Royalties | |
| (47,309 | ) | |
| (91,133 | ) | |
| (60,611 | ) | |
| (80,426 | ) | |
| — | | |
| — | | |
| (107,920 | ) | |
| (171,559 | ) |
| |
| 342,983 | | |
| 490,064 | | |
| 147,857 | | |
| 192,546 | | |
| — | | |
| — | | |
| 490,840 | | |
| 682,610 | |
Expenses | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Operating | |
| 91,354 | | |
| 82,471 | | |
| 28,084 | | |
| 24,955 | | |
| — | | |
| — | | |
| 119,438 | | |
| 107,426 | |
Transportation | |
| 13,240 | | |
| 11,758 | | |
| 1,334 | | |
| — | | |
| — | | |
| — | | |
| 14,574 | | |
| 11,758 | |
Blending and other | |
| 52,995 | | |
| 56,895 | | |
| — | | |
| — | | |
| — | | |
| — | | |
| 52,995 | | |
| 56,895 | |
General and administrative | |
| — | | |
| — | | |
| — | | |
| — | | |
| 15,240 | | |
| 11,640 | | |
| 15,240 | | |
| 11,640 | |
Transaction costs | |
| — | | |
| — | | |
| 7,298 | | |
| — | | |
| 25,534 | | |
| — | | |
| 32,832 | | |
| — | |
Exploration and evaluation | |
| 369 | | |
| 7,210 | | |
| — | | |
| — | | |
| — | | |
| — | | |
| 369 | | |
| 7,210 | |
Depletion and depreciation | |
| 112,262 | | |
| 100,712 | | |
| 62,211 | | |
| 40,097 | | |
| 1,671 | | |
| 1,477 | | |
| 176,144 | | |
| 142,286 | |
Share-based compensation | |
| — | | |
| — | | |
| — | | |
| — | | |
| 16,918 | | |
| 2,942 | | |
| 16,918 | | |
| 2,942 | |
Financing and interest | |
| — | | |
| — | | |
| — | | |
| — | | |
| 34,497 | | |
| 27,077 | | |
| 34,497 | | |
| 27,077 | |
Financial derivatives (gain) loss | |
| — | | |
| — | | |
| — | | |
| — | | |
| 3,038 | | |
| 65,274 | | |
| 3,038 | | |
| 65,274 | |
Foreign exchange (gain) loss | |
| — | | |
| — | | |
| — | | |
| — | | |
| (11,939 | ) | |
| 27,709 | | |
| (11,939 | ) | |
| 27,709 | |
Gain on dispositions | |
| — | | |
| (207 | ) | |
| — | | |
| — | | |
| — | | |
| — | | |
| — | | |
| (207 | ) |
Other (income) expense | |
| — | | |
| (183 | ) | |
| — | | |
| — | | |
| 141 | | |
| 751 | | |
| 141 | | |
| 568 | |
| |
| 270,220 | | |
| 258,656 | | |
| 98,927 | | |
| 65,052 | | |
| 85,100 | | |
| 136,870 | | |
| 454,247 | | |
| 460,578 | |
Net income (loss) before income taxes | |
| 72,763 | | |
| 231,408 | | |
| 48,930 | | |
| 127,494 | | |
| (85,100 | ) | |
| (136,870 | ) | |
| 36,593 | | |
| 222,032 | |
Income tax (recovery) expense | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Current income tax expense | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| 1,350 | | |
| 1,140 | |
Deferred income tax (recovery) expense | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| (178,360 | ) | |
| 39,920 | |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| (177,010 | ) | |
| 41,060 | |
Net income (loss) | |
$ | 72,763 | | |
$ | 231,408 | | |
$ | 48,930 | | |
$ | 127,494 | | |
$ | (85,100 | ) | |
$ | (136,870 | ) | |
$ | 213,603 | | |
$ | 180,972 | |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Additions to exploration and evaluation assets | |
| 741 | | |
| 2,338 | | |
| — | | |
| — | | |
| — | | |
| — | | |
| 741 | | |
| 2,338 | |
Additions to oil and gas properties | |
| 95,662 | | |
| 49,543 | | |
| 74,301 | | |
| 44,752 | | |
| — | | |
| — | | |
| 169,963 | | |
| 94,295 | |
Corporate acquisition, net of cash acquired | |
| — | | |
| — | | |
| 662,439 | | |
| — | | |
| — | | |
| — | | |
| 662,439 | | |
| — | |
Property acquisitions | |
| (62 | ) | |
| 208 | | |
| — | | |
| — | | |
| — | | |
| — | | |
| (62 | ) | |
| 208 | |
Proceeds from dispositions | |
| (50 | ) | |
| (14 | ) | |
| — | | |
| — | | |
| — | | |
| — | | |
| (50 | ) | |
| (14 | ) |
46 | Baytex Energy Corp. Second Quarter Report 2023 | |
| |
Canada | | |
U.S. | | |
Corporate | | |
Consolidated | |
Six Months Ended June 30 | |
2023 | | |
2022 | | |
2023 | | |
2022 | | |
2023 | | |
2022 | | |
2023 | | |
2022 | |
Revenue, net of royalties | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Petroleum and natural gas sales | |
$ | 775,914 | | |
$ | 1,034,901 | | |
$ | 378,182 | | |
$ | 493,093 | | |
$ | — | | |
$ | — | | |
$ | 1,154,096 | | |
$ | 1,527,994 | |
Royalties | |
| (91,164 | ) | |
| (148,809 | ) | |
| (110,009 | ) | |
| (145,470 | ) | |
| — | | |
| — | | |
| (201,173 | ) | |
| (294,279 | ) |
| |
| 684,750 | | |
| 886,092 | | |
| 268,173 | | |
| 347,623 | | |
| — | | |
| — | | |
| 952,923 | | |
| 1,233,715 | |
Expenses | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Operating | |
| 182,534 | | |
| 161,011 | | |
| 49,312 | | |
| 47,181 | | |
| — | | |
| — | | |
| 231,846 | | |
| 208,192 | |
Transportation | |
| 30,245 | | |
| 20,973 | | |
| 1,334 | | |
| — | | |
| — | | |
| — | | |
| 31,579 | | |
| 20,973 | |
Blending and other | |
| 112,676 | | |
| 98,335 | | |
| — | | |
| — | | |
| — | | |
| — | | |
| 112,676 | | |
| 98,335 | |
General and administrative | |
| — | | |
| — | | |
| — | | |
| — | | |
| 26,974 | | |
| 23,322 | | |
| 26,974 | | |
| 23,322 | |
Transaction costs | |
| — | | |
| — | | |
| 7,298 | | |
| — | | |
| 34,405 | | |
| — | | |
| 41,703 | | |
| — | |
Exploration and evaluation | |
| 532 | | |
| 10,780 | | |
| — | | |
| — | | |
| — | | |
| — | | |
| 532 | | |
| 10,780 | |
Depletion and depreciation | |
| 231,733 | | |
| 201,794 | | |
| 107,175 | | |
| 78,461 | | |
| 3,235 | | |
| 2,822 | | |
| 342,143 | | |
| 283,077 | |
Share-based compensation | |
| — | | |
| — | | |
| — | | |
| — | | |
| 26,741 | | |
| 6,887 | | |
| 26,741 | | |
| 6,887 | |
Financing and interest | |
| — | | |
| — | | |
| — | | |
| — | | |
| 58,222 | | |
| 51,321 | | |
| 58,222 | | |
| 51,321 | |
Financial derivatives (gain) loss | |
| — | | |
| — | | |
| — | | |
| — | | |
| (11,587 | ) | |
| 305,901 | | |
| (11,587 | ) | |
| 305,901 | |
Foreign exchange (gain) loss | |
| — | | |
| — | | |
| — | | |
| — | | |
| (12,002 | ) | |
| 13,364 | | |
| (12,002 | ) | |
| 13,364 | |
Loss (gain) on dispositions | |
| 336 | | |
| (441 | ) | |
| — | | |
| — | | |
| — | | |
| — | | |
| 336 | | |
| (441 | ) |
Other (income) expense | |
| (1,271 | ) | |
| (1,465 | ) | |
| — | | |
| — | | |
| 354 | | |
| 1,001 | | |
| (917 | ) | |
| (464 | ) |
| |
| 556,785 | | |
| 490,987 | | |
| 165,119 | | |
| 125,642 | | |
| 126,342 | | |
| 404,618 | | |
| 848,246 | | |
| 1,021,247 | |
Net income (loss) before income taxes | |
| 127,965 | | |
| 395,105 | | |
| 103,054 | | |
| 221,981 | | |
| (126,342 | ) | |
| (404,618 | ) | |
| 104,677 | | |
| 212,468 | |
Income tax (recovery) expense | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Current income tax expense | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| 2,470 | | |
| 2,050 | |
Deferred income tax (recovery) expense | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| (162,837 | ) | |
| (27,412 | ) |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| (160,367 | ) | |
| (25,362 | ) |
Net income (loss) | |
$ | 127,965 | | |
$ | 395,105 | | |
$ | 103,054 | | |
$ | 221,981 | | |
$ | (126,342 | ) | |
$ | (404,618 | ) | |
$ | 265,044 | | |
$ | 237,830 | |
Additions to exploration and evaluation assets | |
| 1,231 | | |
| 5,897 | | |
| — | | |
| — | | |
| — | | |
| — | | |
| 1,231 | | |
| 5,897 | |
Additions to oil and gas properties | |
| 279,778 | | |
| 172,114 | | |
| 123,321 | | |
| 72,444 | | |
| — | | |
| — | | |
| 403,099 | | |
| 244,558 | |
Corporate acquisition, net of cash | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
acquired | |
| — | | |
| — | | |
| 662,439 | | |
| — | | |
| — | | |
| — | | |
| 662,439 | | |
| — | |
Property acquisitions | |
| 444 | | |
| 267 | | |
| — | | |
| — | | |
| — | | |
| — | | |
| 444 | | |
| 267 | |
Proceeds from dispositions | |
| (285 | ) | |
| (41 | ) | |
| — | | |
| — | | |
| — | | |
| — | | |
| (285 | ) | |
| (41 | ) |
| |
June 30, 2023 | | |
December 31, 2022 | |
Canadian assets | |
$ | 2,791,516 | | |
$ | 2,779,596 | |
U.S. assets | |
| 5,755,650 | | |
| 2,301,047 | |
Corporate assets | |
| 70,278 | | |
| 23,126 | |
Total consolidated assets | |
$ | 8,617,444 | | |
$ | 5,103,769 | |
| Baytex Energy Corp. Second Quarter Report 2023 | 47 |
5. EXPLORATION
AND EVALUATION ASSETS |
|
|
|
|
| |
June 30, 2023 | | |
December 31, 2022 | |
Balance, beginning of period | |
$ | 168,684 | | |
$ | 172,824 | |
Capital expenditures | |
| 1,231 | | |
| 6,359 | |
Property acquisitions | |
| 506 | | |
| 301 | |
Divestitures | |
| (788 | ) | |
| (498 | ) |
Property swaps | |
| 978 | | |
| 385 | |
Impairment reversal | |
| — | | |
| 22,503 | |
Exploration and evaluation expense | |
| (532 | ) | |
| (30,239 | ) |
Transfer to oil and gas properties (note 6) | |
| (5,887 | ) | |
| (8,496 | ) |
Foreign currency translation | |
| (1,744 | ) | |
| 5,545 | |
Balance, end of period | |
$ | 162,448 | | |
$ | 168,684 | |
At June 30, 2023 there were no indicators
of impairment or impairment reversal for exploration and evaluation assets in any of the Company's cash generating units ("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 CGU's fair value less costs of disposal ("FVLCD") and was
estimated with reference to arm's length transactions in comparable locations and the discounted cash flows associated with the Company's
future development plans.
6. OIL AND GAS PROPERTIES |
|
|
|
|
|
|
| |
| | |
Accumulated | | |
| |
| |
Cost | | |
depletion | | |
Net book value | |
Balance, December 31, 2021 | |
$ | 11,633,517 | | |
$ | (7,169,146 | ) | |
$ | 4,464,371 | |
Capital expenditures | |
| 515,183 | | |
| — | | |
| 515,183 | |
Property acquisitions | |
| 1,173 | | |
| — | | |
| 1,173 | |
Transfers from exploration and evaluation assets (note 5) | |
| 8,496 | | |
| — | | |
| 8,496 | |
Change in asset retirement obligations (note 9) | |
| (147,020 | ) | |
| — | | |
| (147,020 | ) |
Divestitures | |
| (265,166 | ) | |
| 241,892 | | |
| (23,274 | ) |
Property swaps | |
| — | | |
| — | | |
| — | |
Impairment reversal | |
| — | | |
| 245,241 | | |
| 245,241 | |
Foreign currency translation | |
| 296,033 | | |
| (158,404 | ) | |
| 137,629 | |
Depletion | |
| — | | |
| (581,033 | ) | |
| (581,033 | ) |
Balance, December 31, 2022 | |
$ | 12,042,216 | | |
$ | (7,421,450 | ) | |
$ | 4,620,766 | |
Capital expenditures | |
| 403,099 | | |
| — | | |
| 403,099 | |
Corporate acquisition (note 3) | |
| 3,081,596 | | |
| — | | |
| 3,081,596 | |
Transfers from exploration and evaluation assets (note 5) | |
| 5,887 | | |
| — | | |
| 5,887 | |
Change in asset retirement obligations (note 9) | |
| 37,017 | | |
| — | | |
| 37,017 | |
Divestitures | |
| (1,997 | ) | |
| 1,511 | | |
| (486 | ) |
Property swaps | |
| (4,733 | ) | |
| 3,756 | | |
| (977 | ) |
Foreign currency translation | |
| (104,963 | ) | |
| 56,694 | | |
| (48,269 | ) |
Depletion | |
| — | | |
| (338,908 | ) | |
| (338,908 | ) |
Balance, June 30, 2023 | |
$ | 15,458,122 | | |
$ | (7,698,397 | ) | |
$ | 7,759,725 | |
At June 30, 2023, there were no indicators
of impairment or impairment reversal for oil and gas properties in any of the Company's CGUs.
48 | Baytex Energy Corp. Second Quarter Report 2023 | |
At
December 31, 2022, the Company identified indicators of impairment reversal for oil and gas properties in five of our six CGUs due
to the increase in forecasted commodity prices in addition to changes in proved plus probable reserves. The recoverable amounts 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 was based on its FVLCD which was estimated using a discounted cash flow model of proved plus probable
cash flows from an independent reserve report prepared as at December 31, 2022. The after-tax discount rates applied to the cash
flows were between 12% and 23%.
| |
June 30, 2023 | | |
December 31, 2022 | |
Credit facilities - U.S. dollar denominated (1) | |
$ | 413,785 | | |
$ | 30,394 | |
Credit facilities - Canadian dollar denominated | |
| 374,555 | | |
| 355,000 | |
Term loan - U.S. dollar denominated (1) | |
| 198,563 | | |
| — | |
Credit facilities - principal (2) | |
| 986,903 | | |
| 385,394 | |
Unamortized debt issuance costs | |
| (22,571 | ) | |
| (2,363 | ) |
Credit facilities | |
$ | 964,332 | | |
$ | 383,031 | |
| (1) | U.S. dollar denominated
credit facilities balance was US$462.6 million as at June 30, 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 June 30,
2023 is the result of net draws of $602.5 million as well as changes in the reported amount
of U.S. denominated debt of $1.0 million due to foreign exchange. |
At June 30, 2023, Baytex had US$1.1 billion
of revolving credit facilities (the "Revolving Facilities) and a US$150 million term loan (the "Term Loan") (collectively
the "Credit Facilities"). On June 20, 2023, in connection with the acquisition of Ranger, Baytex amended its Credit Facilities
to increase the committed amount (previously US$850 million in aggregate as of April 1, 2022) and entered into a secured two-year
term loan of US$150 million that will mature on June 20, 2025. The maturity date of the Revolving Facilities is April 1, 2026.
The Revolving 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 are not borrowing base facilities
and do not require annual or semi-annual reviews. 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 6.5% for the six months ended June 30, 2023 (2.6% for six months ended June 30, 2022).
The following table summarizes the financial
covenants applicable to the Credit Facilities and our compliance therewith at June 30, 2023.
| |
| Position as at | | |
| | |
Covenant Description | |
| June 30, 2023 | | |
| Covenant | |
Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio) | |
| 0.5:1.0 | | |
| 3.5:1.0 | |
Interest Coverage (3) (Minimum Ratio) | |
| 13.3:1.0 | | |
| 3.5:1.0 | |
Total Debt (4) to Bank EBITDA (2) (Maximum Ratio) | |
| 1.2:1.0 | | |
| 4:0:1.0 | |
| (1) | "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 June 30, 2023, the Company's Senior Secured Debt
totaled $986.9 million of principal amounts outstanding.
|
| (2) | "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 June 30, 2023 was $2.1 billion. |
| (3) | "Interest
coverage" is calculated in accordance with the credit facility agreement and is computed
as the ratio of Bank EBITDA to financing and interest expense, excluding certain non-cash
transactions, and is calculated on a trailing twelve-month basis. Financing and interest
expense for the twelve months ended June 30, 2023 was $155.8 million. |
| (4) | "Total
Debt" is calculated in accordance with the credit facility agreement and is defined
as all obligations, liabilities, and indebtedness of Baytex excluding trade and other payables,
asset retirement obligations, leases, deferred income tax liabilities, and financial derivative
liabilities. As at June 30, 2023, the Company's Total Debt totaled $2.6 billion of principal
amounts outstanding. |
| Baytex Energy Corp. Second Quarter Report 2023 | 49 |
At
June 30, 2023, Baytex had $16.8 million of outstanding letters of credit, $15.5 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.
| |
June 30, 2023 | | |
December 31, 2022 | |
8.75% notes due April 1, 2027 (1) | |
$ | 542,467 | | |
$ | 554,597 | |
8.50% notes due April 1, 2030 (2) | |
| 1,059,001 | | |
| — | |
Total long-term notes - principal (3) | |
| 1,601,468 | | |
| 554,597 | |
Unamortized debt issuance costs | |
| (37,571 | ) | |
| (6,999 | ) |
Total long-term notes - net of discount and unamortized debt issuance costs | |
$ | 1,563,897 | | |
$ | 547,598 | |
| (1) | The U.S. dollar denominated principal
outstanding of the 8.75% notes was US$409.8 million as at June 30, 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 as at June 30, 2023 (December 31,
2022 - nil). |
| (3) | The increase in the principal
amount of long-term notes outstanding from December 31, 2022 to June 30, 2023 is
the result of the issuance of the 8.50% notes for $1.1 billion partially offset by changes
in the reported amount of U.S. denominated debt of $13.0 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.
9. ASSET RETIREMENT OBLIGATIONS |
|
|
|
|
| |
June 30, 2023 | | |
December 31, 2022 | |
Balance, beginning of period | |
$ | 588,923 | | |
$ | 743,683 | |
Liabilities incurred (1) | |
| 11,302 | | |
| 19,942 | |
Liabilities settled | |
| (9,518 | ) | |
| (18,351 | ) |
Liabilities assumed from corporate acquisition (note 3) | |
| 31,310 | | |
| — | |
Liabilities acquired from property acquisitions | |
| — | | |
| 950 | |
Liabilities divested | |
| (590 | ) | |
| (3,464 | ) |
Accretion (note 15) | |
| 9,221 | | |
| 15,683 | |
Government grants (2) | |
| (1,271 | ) | |
| (4,009 | ) |
Change in estimate (1) | |
| 4,958 | | |
| 6,124 | |
Changes in discount rates and inflation rates (1)(3) | |
| 20,757 | | |
| (173,086 | ) |
Foreign currency translation | |
| (522 | ) | |
| 1,451 | |
Balance, end of period | |
$ | 654,570 | | |
$ | 588,923 | |
Less current portion of asset retirement obligations | |
| 12,965 | | |
| 12,813 | |
Non-current portion of asset retirement obligations | |
$ | 641,605 | | |
$ | 576,110 | |
| (1) | Agrees
to total change in asset retirement obligations of $37.0 million per Note 6 - Oil and Gas
Properties. |
| (2) | During
the six months ended June 30, 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 for the year
ended December 31, 2022). |
| (3) | The
discount and inflation rates used to calculate the liability for our Canadian operations
at June 30, 2023 were 3.1% and 1.7%, 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 June 30, 2023 were 3.9% and 2.2%, respectively (December 31, 2022 - 3.3% and
2.1%). Baytex used a risk-free discount rate for the U.S operations liability at Q2 2023
(previously used a credit-adjusted rate). |
50 | Baytex Energy Corp. Second Quarter Report 2023 | |
10. 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. At June 30, 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.
In June 2023, the TSX accepted Baytex's notice
of intention to renew its Normal Course Issuer Bid ("NCIB"). Under the terms of the NCIB, the Company may purchase for cancellation
up to 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 public float as at June 21, 2023. On June 21, 2023 Baytex had 856.9 million common shares outstanding.
Purchases are made on the open market at prices prevailing at the time of the transaction. Subsequent to June 30, 2023 and through
to July 26, 2023, Baytex repurchased 4.7 million common shares under the NCIB at an average price of $4.59 per share.
Subsequent to June 30, 2023, the Company's
Board of Directors declared a quarterly cash dividend of $0.0225 per share to be paid on October 2, 2023 for shareholders of record
as at September 15, 2023.
| |
Number of | | |
| |
| |
Common Shares | | |
| |
| |
(000s) | | |
Amount | |
Balance, December 31, 2021 | |
| 564,213 | | |
$ | 5,736,593 | |
Vesting of share awards | |
| 5,035 | | |
| 8,501 | |
Common shares repurchased and cancelled | |
| (24,318 | ) | |
| (245,430 | ) |
Balance, December 31, 2022 | |
| 544,930 | | |
$ | 5,499,664 | |
Issued on corporate acquisition (note 3) | |
| 311,370 | | |
| 1,326,435 | |
Vesting of share awards | |
| 5,892 | | |
| 26,229 | |
Balance, June 30, 2023 | |
| 862,192 | | |
$ | 6,852,328 | |
11. SHARE-BASED COMPENSATION PLAN
For the three and six months ended June 30,
2023 the Company recorded total share-based compensation expense of $16.9 million and $26.7 million respectively ($2.9 million and $6.9
million for the three and six months ended June 30, 2022) which are comprised of $16.2 million of non-cash expense related to awards
assumed in the acquisition of Ranger and were settled with Baytex common shares after closing of the business combination and the expense
related to cash-settled awards and the associated equity total return swaps ($2.6 million and $4.8 million for the three and six months
ended June 30, 2022).
The Company's closing share price on the Toronto Stock Exchange on
June 30, 2023 was $4.32 (June 30, 2022 - $6.25).
Share Award Incentive Plan
Baytex has a Share Award Incentive Plan pursuant
to which it issues restricted and performance awards. A restricted award entitles the holder of each award to receive one common share
of Baytex 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 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 trade and other payables.
On June 20, 2023, Baytex became the successor
to Ranger's Share Award Plan. 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 six months ended June 30, 2023 was $5.41 per restricted and performance award ($5.68 for the six months ended
June 30, 2022).
| Baytex Energy Corp. Second Quarter Report 2023 | 51 |
The
number of share awards outstanding is detailed below.
| |
Number of | | |
Number of
performance | | |
Total number of | |
(000s) | |
restricted awards | | |
| awards | | |
| share awards | |
Balance, December 31, 2021 | |
| 2,093 | | |
| 7,381 | | |
| 9,474 | |
Granted | |
| 68 | | |
| 1,391 | | |
| 1,459 | |
Added by performance factor | |
| — | | |
| — | | |
| — | |
Vested | |
| (1,377 | ) | |
| (3,630 | ) | |
| (5,007 | ) |
Forfeited | |
| (22 | ) | |
| (346 | ) | |
| (368 | ) |
Balance, December 31, 2022 | |
| 762 | | |
| 4,796 | | |
| 5,558 | |
Granted | |
| — | | |
| 2,599 | | |
| 2,599 | |
Assumed on corporate acquisition (1) | |
| 10,789 | | |
| — | | |
| 10,789 | |
Vested | |
| (9,302 | ) | |
| (3,767 | ) | |
| (13,069 | ) |
Forfeited | |
| (10 | ) | |
| (234 | ) | |
| (244 | ) |
Balance, June 30, 2023 | |
| 2,239 | | |
| 3,394 | | |
| 5,633 | |
| (1) | Follow 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 (note 3) 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
holder of each incentive award is entitled to receive a cash payment equal to the value of one Baytex common share at the time of vesting.
The incentive awards vest in equal tranches on the first, second and third anniversaries of the grant date. The cumulative expense is
recognized at fair value at each period end and is included in trade and other payables.
During the six months ended June 30, 2023,
Baytex granted 2.4 million awards under the Incentive Award plan at a fair value of $5.39 per award (1.3 million awards at $5.68 per award
for the six months ended June 30, 2022). At June 30, 2023 there were 4.6 million awards outstanding under the Incentive Award
plan (5.1 million awards outstanding at December 31, 2022).
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 trade and other payables.
During the six months ended June 30, 2023,
Baytex granted 0.2 million awards under the DSU plan at a fair value of $5.49 per award (0.2 million awards at $5.68 per award for the
six months ended June 30, 2022). At June 30, 2023, there were 1.2 million awards outstanding under the DSU plan.
Equity Total Return Swaps
The Company uses equity total return swaps on
the equivalent number of Baytex common shares in order to fix the aggregate cost of the Company's cash-settled DSU Plan, at the fair value
determined on the grant date.
At June 30, 2023, an asset of $0.7 million
associated with the equity return swap was included in trade and other receivables (December 31, 2022 - $21.2 million).
12. NET 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 period.
52 | Baytex Energy Corp. Second Quarter Report 2023 | |
| |
Three Months Ended June 30 | |
| |
2023 | | |
2022 | |
| |
| | |
Weighted | | |
| | |
| | |
Weighted | | |
| |
| |
| | |
average | | |
| | |
| | |
average | | |
| |
| |
| | |
common | | |
| | |
| | |
common | | |
| |
| |
| | |
shares | | |
Net income | | |
| | |
shares | | |
Net income | |
| |
Net income | | |
(000s) | | |
per share | | |
Net income | | |
(000s) | | |
per share | |
Net income - basic | |
$ |
213,603 | | |
583,365 | | |
$0.37 | | |
$ |
180,972 | | |
566,997 | | |
$0.32 | |
Dilutive effect of share awards | |
| — | | |
4,805 | | |
| — | | |
| — | | |
| 4,700 | | |
| — | |
Net income - diluted | |
$ | 213,603 | | |
588,170 | | |
$ | 0.36 | | |
$ | 180,972 | | |
| 571,697 | | |
$ | 0.32 | |
| |
Six Months Ended June 30 | |
| |
2023 | | |
2022 | |
| |
| | |
Weighted | | |
| | | |
| | |
| | |
| | |
| |
| | |
average | | |
| | | |
| | |
Weighted | | |
| | |
| |
| | |
common | | |
| | | |
| | |
average | | |
| | |
| |
| | |
shares | | |
Net income | | |
| | |
common | | |
Net income | |
| |
Net income | | |
(000s) | | |
per share | | |
Net income | | |
shares (000s) | | |
per share | |
Net income - basic | |
$ |
265,044 | | |
|
564,319 | | |
$ | 0.47 | | |
$ |
237,830 | | |
|
566,262 | | |
$ | 0.42 | |
Dilutive effect of share awards | |
|
— | | |
|
4,965 | | |
| — | | |
|
— | | |
|
4,582 | | |
| — | |
Net income - diluted | |
$ |
265,044 | | |
|
569,284 | | |
$ | 0.47 | | |
$ |
237,830 | | |
|
570,844 | | |
$ | 0.42 | |
For the three and six months ended June 30, 2023 and June 30,
2022 no share awards were excluded from the calculation of diluted income per share as all of their affects were dilutive.
13. 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.
| |
Three Months Ended June 30 | |
| |
2023 | | |
2022 | |
| |
Canada | | |
U.S. | | |
Total | | |
Canada | | |
U.S. | | |
Total | |
Light oil and condensate | |
$ | 124,965 | | |
$ | 183,845 | | |
$ | 308,810 | | |
$ | 192,986 | | |
$ | 222,606 | | |
$ | 415,592 | |
Heavy oil | |
| 251,449 | | |
| — | | |
| 251,449 | | |
| 346,101 | | |
| — | | |
| 346,101 | |
NGL | |
| 3,772 | | |
| 16,391 | | |
| 20,163 | | |
| 8,288 | | |
| 24,895 | | |
| 33,183 | |
Natural gas sales | |
| 10,106 | | |
| 8,232 | | |
| 18,338 | | |
| 33,822 | | |
| 25,471 | | |
| 59,293 | |
Total petroleum and natural gas sales | |
$ | 390,292 | | |
$ | 208,468 | | |
$ | 598,760 | | |
$ | 581,197 | | |
$ | 272,972 | | |
$ | 854,169 | |
| |
Six Months Ended June 30 | |
| |
2023 | | |
2022 | |
| |
Canada | | |
U.S. | | |
Total | | |
Canada | | |
U.S. | | |
Total | |
Light oil and condensate | |
$ | 271,420 | | |
$ | 325,855 | | |
$ | 597,275 | | |
$ | 373,141 | | |
$ | 403,426 | | |
$ | 776,567 | |
Heavy oil | |
| 468,534 | | |
| — | | |
| 468,534 | | |
| 590,539 | | |
| — | | |
| 590,539 | |
NGL | |
| 9,832 | | |
| 32,165 | | |
| 41,997 | | |
| 15,772 | | |
| 46,902 | | |
| 62,674 | |
Natural gas sales | |
| 26,128 | | |
| 20,162 | | |
| 46,290 | | |
| 55,449 | | |
| 42,765 | | |
| 98,214 | |
Total petroleum and natural gas sales | |
$ | 775,914 | | |
$ | 378,182 | | |
$ | 1,154,096 | | |
$ | 1,034,901 | | |
$ | 493,093 | | |
$ | 1,527,994 | |
Included in accounts receivable at June 30,
2023 is $294.4 million of accrued production revenue related to delivered volumes (December 31, 2022 - $183.0 million).
| Baytex Energy Corp. Second Quarter Report 2023 | 53 |
14. INCOME TAXES
The provision for income taxes has been computed as follows:
| |
Six Months Ended June 30 | |
| |
2023 | | |
2022 | |
Net income (loss) before income taxes | |
| 104,677 | | |
$ | 212,468 | |
Expected income taxes at the statutory rate of 24.80% (2022 – 25.12%) | |
| 25,960 | | |
| 53,372 | |
Change in income taxes resulting from: | |
| | | |
| | |
Effect of foreign exchange | |
| (1,612 | ) | |
| 984 | |
Effect of rate adjustments for foreign jurisdictions | |
| (2,883 | ) | |
| (18,357 | ) |
Effect of change in deferred tax benefit not recognized (1) | |
| (1,613 | ) | |
| (17,823 | ) |
Effect of internal debt restructuring (2) | |
| (186,460 | ) | |
| (45,182 | ) |
Adjustments, assessments and other | |
| 6,241 | | |
| 1,644 | |
Income tax expense (recovery) | |
$ | (160,367 | ) | |
$ | (25,362 | ) |
| (1) | A deferred income tax asset
of $13.6 million remains unrecognized due to uncertainty surrounding future capital gains
(December 31, 2022-$14.4 million). The unrecognized deferred income tax asset relates
to realized and unrealized foreign exchange losses arising from the repayment of previously
issued U.S. dollar denominated long-term notes and from the translation of U.S. dollar denominated
long-term notes currently outstanding. |
| (2) | A deferred income tax asset
has been recognized immediately after the closing of the Ranger acquisition due to effects
of the transaction structuring. |
As disclosed in the 2022 annual financial statements,
certain indirect subsidiary entities received reassessments from the Canada Revenue Agency (the “CRA”) in June 2016 that
denied $591.0 million of non-capital loss deductions that relate to the calculation of income taxes for the years 2011 through 2015. In
September 2016, Baytex filed notices of objection with the CRA appealing each reassessment received. In July 2023, Baytex received
a letter from the Appeals Division of the CRA proposing to confirm the reassessments. Baytex remains confident that the original tax filings
are correct and intends to defend these tax filings through the appeals process.
15. FINANCING AND INTEREST |
|
|
|
|
|
|
|
|
|
| |
Three Months Ended June 30 | | |
Six Months Ended June 30 | |
| |
2023 | | |
2022 | | |
2023 | | |
2022 | |
Interest on Credit Facilities | |
$ | 7,535 | | |
$ | 4,070 | | |
$ | 13,751 | | |
$ | 7,109 | |
Interest on long-term notes | |
| 20,565 | | |
| 16,356 | | |
| 32,659 | | |
| 33,700 | |
Interest on lease obligations | |
| 155 | | |
| 48 | | |
| 220 | | |
| 92 | |
Cash Interest | |
$ | 28,255 | | |
$ | 20,474 | | |
$ | 46,630 | | |
$ | 40,901 | |
Amortization of debt issue costs | |
| 1,847 | | |
| 2,734 | | |
| 2,371 | | |
| 3,429 | |
Accretion on asset retirement obligations (note 9) | |
| 4,395 | | |
| 3,869 | | |
| 9,221 | | |
| 6,991 | |
Financing and interest | |
$ | 34,497 | | |
$ | 27,077 | | |
$ | 58,222 | | |
$ | 51,321 | |
| |
Three Months Ended June 30 | | |
Six Months Ended June 30 | |
| |
2023 | | |
2022 | | |
2023 | | |
2022 | |
Unrealized foreign exchange gain - intercompany notes (1) | |
$ | — | | |
$ | — | | |
$ | — | | |
$ | (2,674 | ) |
Unrealized foreign exchange (gain) loss - long-term notes & Credit Facilities | |
| (12,880 | ) | |
| 27,499 | | |
| (13,093 | ) | |
| 15,625 | |
Realized foreign exchange loss | |
| 941 | | |
| 210 | | |
| 1,091 | | |
| 413 | |
Foreign exchange (gain) loss | |
$ | (11,939 | ) | |
$ | 27,709 | | |
$ | (12,002 | ) | |
$ | 13,364 | |
| (1) | Baytex had a series of intercompany
notes totaling US$601.0 million outstanding at December 31, 2021 that were issued from
a Canadian functional currency subsidiary to a U.S. functional currency subsidiary. These
notes were eliminated upon consolidation within the Statement of Financial Position and were
revalued at the relevant foreign exchange rate at each period end. Foreign exchange gains
or losses incurred within the Canadian functional currency subsidiary were recognized in
unrealized foreign exchange gain or loss whereas those within the U.S. functional currency
subsidiary were recognized in other comprehensive income. In January 2022 the intercompany
notes were transferred from the Canadian functional currency subsidiary to another U.S. functional
currency subsidiary. As a result, foreign exchange gains and losses incurred on these notes
after the transfer are recognized in other comprehensive income. |
54 | Baytex Energy Corp. Second Quarter Report 2023 | |
17.
FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
The Company's financial assets and liabilities
are comprised of cash, trade and other receivables, trade and other payables, financial derivatives, Credit Facilities, and long-term
notes. The fair value of trade and other receivables and trade and other payables 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 condensed consolidated statements of financial position are classified into the following categories:
| |
June 30, 2023 | | |
December 31, 2022 | |
| |
| | |
| | |
| | |
| | |
Fair Value | |
| |
| | |
| | |
| | |
| | |
Measurement | |
| |
Carrying value | | |
Fair value | | |
Carrying value | | |
Fair value | | |
Hierarchy | |
Financial Assets | |
| | | |
| | | |
| | | |
| | | |
| | |
Fair value through profit and loss | |
| | | |
| | | |
| | | |
| | | |
| | |
Financial derivatives | |
$ | 27,505 | | |
$ | 27,505 | | |
$ | 10,105 | | |
$ | 10,105 | | |
| Level 2 | |
Total | |
$ | 27,505 | | |
$ | 27,505 | | |
$ | 10,105 | | |
$ | 10,105 | | |
| | |
| |
| | | |
| | | |
| | | |
| | | |
| | |
Amortized cost | |
| | | |
| | | |
| | | |
| | | |
| | |
Cash | |
$ | 19,637 | | |
$ | 19,637 | | |
$ | 5,464 | | |
$ | 5,464 | | |
| — | |
Trade and other receivables | |
| 370,498 | | |
| 370,498 | | |
| 228,485 | | |
| 228,485 | | |
| — | |
Total | |
$ | 390,135 | | |
$ | 390,135 | | |
$ | 233,949 | | |
$ | 233,949 | | |
| | |
| |
| | | |
| | | |
| | | |
| | | |
| | |
Financial Liabilities | |
| | | |
| | | |
| | | |
| | | |
| | |
Fair value through profit and loss | |
| | | |
| | | |
| | | |
| | | |
| | |
Financial derivatives | |
$ | (2,907 | ) | |
$ | (2,907 | ) | |
$ | — | | |
$ | — | | |
| Level 2 | |
Total | |
$ | (2,907 | ) | |
$ | (2,907 | ) | |
$ | — | | |
$ | — | | |
| | |
| |
| | | |
| | | |
| | | |
| | | |
| | |
Amortized cost | |
| | | |
| | | |
| | | |
| | | |
| | |
Trade and other payables | |
$ | (616,608 | ) | |
$ | (616,608 | ) | |
$ | (281,404 | ) | |
$ | (281,404 | ) | |
| — | |
Credit Facilities | |
| (964,332 | ) | |
| (986,903 | ) | |
| (383,031 | ) | |
| (385,394 | ) | |
| — | |
Long-term notes | |
| (1,563,897 | ) | |
| (1,585,368 | ) | |
| (547,598 | ) | |
| (563,292 | ) | |
| Level 1 | |
Total | |
$ | (3,144,837 | ) | |
$ | (3,188,879 | ) | |
$ | (1,212,033 | ) | |
$ | (1,230,090 | ) | |
| | |
There were no transfers between Level 1 and Level 2 during the six
months ended June 30, 2023 and 2022.
Foreign Currency Risk
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:
| |
Assets | | |
Liabilities | |
| |
June 30, 2023 | | |
December 31, 2022 | | |
June 30, 2023 | | |
December 31, 2022 | |
U.S. dollar denominated | |
| US$20,537 | | |
| US$6,980 | | |
| US$1,331,541 | | |
| US$430,171 | |
| Baytex Energy Corp. Second Quarter Report 2023 | 55 |
Commodity Price Risk
Financial Derivative Contracts
Baytex had the following financial derivative contracts outstanding
as of July 27, 2023:
| |
Remaining Period | |
Volume | |
Price/Unit (1) | |
Index |
Oil | |
| |
| |
| |
|
Basis differential (2) | |
July 2023 to Dec 2023 | |
1,500 bbl/d | |
WTI less US$2.50/bbl | |
MSW |
Basis differential (2)(3) | |
Jan 2024 to Dec 2024 | |
1,500 bbl/d | |
WTI less US$2.65/bbl | |
MSW |
Basis differential (2) | |
July 2023 to Dec 2023 | |
2,000 bbl/d | |
WTI less US$14.98/bbl | |
WCS |
Basis differential (2) | |
Aug 2023 to Dec 2023 | |
6,000 bbl/d | |
WTI less US$13.62/bbl | |
WCS |
| |
| |
| |
Baytex pays: WCS differential at Hardisty | |
|
Basis differential (2) | |
July 2023 to Dec 2023 | |
5,000 bbl/d | |
Baytex receives: WCS differential at Houston less
US$8.10/bbl | |
WCS |
Basis differential (2) | |
Jan 2024 to Jun 2024 | |
4,000 bbl/d | |
Baytex pays: WCS differential at Hardisty
Baytex receives: WCS differential at Houston less
US$8.10/bbl | |
WCS |
Put option | |
July 2023 to Dec 2023 | |
5,000 bbl/d | |
US$60.00 | |
WTI |
Collar | |
July 2023 to Dec 2023 | |
15,500 bbl/d | |
US$60.00/US$100.00 | |
WTI |
Collar | |
July 2023 to Sep 2023 | |
19,862 bbl/d | |
US$60.00/US$100.00 | |
WTI |
Collar | |
Oct 2023 to Dec 2023 | |
15,089 bbl/d | |
US$60.00/US$100.00 | |
WTI |
Collar | |
Jan 2024 to Mar 2024 | |
8,400 bbl/d | |
US$60.00/US$100.00 | |
WTI |
Collar | |
Apr 2024 to Jun 2024 | |
1,750 bbl/d | |
US$60.00/US$100.00 | |
WTI |
Collar | |
Jan 2024 to Jun 2024 | |
14,500 bbl/d | |
US$60.00/US$100.00 | |
WTI |
Collar (3) | |
Jan 2024 to Jun 2024 | |
2,500 bbl/d | |
US$60.00/US$90.00 | |
WTI |
| |
| |
| |
| |
|
Natural Gas | |
| |
| |
| |
|
| |
| |
| |
Baytex pays: NYMEX | |
HSC IFERC |
Basis differential (2) | |
July 2023 to Dec 2023 | |
11,413 mmbtu/d | |
Baytex receives: HSC less US$0.1525/mmbtu | |
FOM |
Fixed Sell | |
Oct 2023 to Mar 2024 | |
3,500 mmbtu/d | |
US$3.5025/mmbtu | |
NYMEX |
Collar | |
July 2023 to Dec 2023 | |
11,413 mmbtu/d | |
US$2.50/US$2.68 | |
NYMEX |
Collar | |
Jan 2024 to Mar 2024 | |
11,538 mmbtu/d | |
US$2.50/US$3.65 | |
NYMEX |
Collar | |
Apr 2024 to Jun 2024 | |
11,538 mmbtu/d | |
US$2.33/US$3.00 | |
NYMEX |
Collar | |
Jan 2024 to Dec 2024 | |
2,500 mmbtu/d | |
US$3.00/US$4.06 | |
NYMEX |
Collar | |
Jan 2024 to Dec 2024 | |
2,500 mmbtu/d | |
US$3.00/US$4.09 | |
NYMEX |
Collar | |
Jan 2024 to Dec 2024 | |
5,000 mmbtu/d | |
US$3.00/US$4.10 | |
NYMEX |
Collar | |
Jan 2024 to Dec 2024 | |
8,500 mmbtu/d | |
US$3.00/US$4.15 | |
NYMEX |
Collar | |
Jan 2024 to Dec 2024 | |
5,000 mmbtu/d | |
US$3.00/US$4.19 | |
NYMEX |
| |
| |
| |
| |
|
Natural Gas Liquids | |
| |
| |
| |
|
| |
| |
| |
| |
Mt. Belvieu |
| |
| |
| |
| |
Non-TET |
Fixed Sell | |
Jul 2023 to Mar 2024 | |
34,364 gallon/d | |
US$0.2280/gallon | |
Ethane |
| (1) | Based on the weighted average
price per unit for the period. |
| (2) | Contracts that fix the basis
differential between certain oil reference prices. |
| (3) | Contract entered subsequent
to June 30, 2023. |
The following table sets forth the realized and unrealized gains and
losses recorded on financial derivatives.
| |
Three Months Ended June 30 | | |
Six Months Ended June 30 | |
| |
2023 | | |
2022 | | |
2023 | | |
2022 | |
Realized financial derivatives (gain) loss | |
$ | (16,365 | ) | |
$ | 124,042 | | |
$ | (21,780 | ) | |
$ | 208,408 | |
Unrealized financial derivatives (gain) loss | |
| 19,403 | | |
| (58,768 | ) | |
| 10,193 | | |
| 97,493 | |
Financial derivatives (gain) loss | |
$ | 3,038 | | |
$ | 65,274 | | |
$ | (11,587 | ) | |
$ | 305,901 | |
56 | Baytex Energy Corp. Second Quarter Report 2023 | |
18. CAPITAL MANAGEMENT
The Company's capital management objective is
to maintain financial flexibility and sufficient sources of liquidity to execute its capital programs, while meeting short and long-term
commitments. Baytex strives to actively manage its capital structure in response to changes in economic conditions. At June 30, 2023,
the Company's capital structure was comprised of shareholders' capital, long-term notes, trade and other receivables, trade and other
payables, 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 and other payables, cash, and trade and other receivables.
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.
| |
June 30, 2023 | | |
December 31, 2022 | |
Credit Facilities | |
$ | 964,332 | | |
$ | 383,031 | |
Unamortized debt issuance costs - Credit Facilities (note 7) | |
| 22,571 | | |
| 2,363 | |
Long-term notes | |
| 1,563,897 | | |
| 547,598 | |
Unamortized debt issuance costs - Long-term notes (note 8) | |
| 37,571 | | |
| 6,999 | |
Trade and other payables | |
| 616,608 | | |
| 281,404 | |
Cash | |
| (19,637 | ) | |
| (5,464 | ) |
Trade and other receivables | |
| (370,498 | ) | |
| (228,485 | ) |
Net Debt | |
$ | 2,814,844 | | |
$ | 987,446 | |
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.
| |
Three Months Ended June 30 | | |
Six Months Ended June 30 | |
| |
2023 | | |
2022 | | |
2023 | | |
2022 | |
Cash flows from operating activities | |
$ | 192,308 | | |
$ | 360,034 | | |
$ | 377,246 | | |
$ | 559,008 | |
Change in non-cash working capital | |
| 40,795 | | |
| (17,046 | ) | |
| 79,849 | | |
| 60,294 | |
Asset retirement obligations settled | |
| 5,392 | | |
| 2,716 | | |
| 9,518 | | |
| 6,009 | |
Transaction costs | |
| 32,832 | | |
| — | | |
| 41,703 | | |
| — | |
Cash premiums on derivatives | |
| 2,263 | | |
| | | |
| 2,263 | | |
| | |
Adjusted Funds Flow | |
$ | 273,590 | | |
$ | 345,704 | | |
$ | 510,579 | | |
$ | 625,311 | |
| Baytex Energy Corp. Second Quarter Report 2023 | 57 |
CORPORATE
INFORMATION
BOARD OF DIRECTORS |
|
Mark R. Bly |
Chairman of the Board |
|
Eric T. Greager |
Director |
|
Tiffany (TJ) Thom Cepak |
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 |
Director |
| (1) | Member of the Audit Committee |
| (2) | Member of the Human Resources and Compensation
Committee |
| (3) | Member of the Reserves and Sustainability
Committee |
| (4) | Member of the Nominating and Governance Committee |
HEAD OFFICE
Baytex Energy Corp.
Centennial Place, East Tower
2800, 520 - 3rd Avenue SW
Calgary, Alberta T2P 0R3
Toll-free 1.800.524.5521
T 587.952.3000
F 587.952.3001
WWW.BAYTEXENERGY.COM
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 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 Lessoway
Vice President, Finance
and Treasurer
Kayla D. Baird
Vice President, U.S. Accounting
and Corporate Services
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
Design: ARTHUR / HUNTER
Printing: Merrill Corporation
Baytex Energy (PK) (USOTC:BTEGF)
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From May 2024 to Jun 2024
Baytex Energy (PK) (USOTC:BTEGF)
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From Jun 2023 to Jun 2024