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 July 2024
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: July 30, 2024
Exhibit 99.1
BAYTEX ANNOUNCES SECOND QUARTER 2024 RESULTS
CALGARY, ALBERTA (July 25, 2024) - Baytex
Energy Corp. ("Baytex") (TSX:BTE) (NYSE:BTE) reports its operating and financial results for the three and six months ended
June 30, 2024 (all amounts are in Canadian dollars unless otherwise noted).
"We delivered strong second quarter results
with higher production, disciplined capital spending and meaningful free cash flow. Importantly and consistent with our full-year plan,
we returned $97 million to shareholders through our share buyback program and quarterly dividend. In the Eagle Ford, we brought onstream
one of our strongest performing oil-weighted pads to-date. As we continue to execute our plans for 2024, our free cash flow is expected
to strengthen in the second half of the year allowing for increased shareholder returns and debt reduction," commented Eric T. Greager,
President and Chief Executive Officer.
Highlights
| · | Generated
production of 154,194 boe/d (85% oil and NGL) in Q2/2024, up 2% from Q1/2024. Crude oil production
(light oil, condensate, and heavy oil) increased 4% from Q1/2024 to average 110,734 bbl/d. |
| · | Increased
production per basic share by 23% in Q2/2024, compared to Q2/2023. |
| · | Reported
cash flows from operating activities of $506 million ($0.62 per basic share) in Q2/2024. |
| · | Delivered
adjusted funds flow(1) of $533 million ($0.65 per basic share) in Q2/2024. |
| · | Generated
free cash flow(2) of $181 million ($0.22 per basic share) in Q2/2024 and
returned $97 million to shareholders. |
| · | Repurchased
16.4 million common shares in Q2/2024 for $79 million, at an average price of $4.84 per share. |
| · | Paid
a quarterly cash dividend of $18 million ($0.0225 per share) on July 2, 2024. |
| · | Executed
a $340 million exploration and development program in Q2/2024, consistent with our full-year
plan. |
| · | Completed
a US$575 million private placement offering of senior unsecured notes due 2032 that bear
interest at a rate of 7.375% per annum and redeemed US$410 million aggregate principal amount
of 8.75% outstanding notes. |
| · | Extended
the maturity of our US$1.1 billion credit facilities by two years to May 2028. |
| · | Maintained
balance sheet strength with a total debt(3) to Bank EBITDA(3) ratio
of 1.1x. |
2024 Guidance
We are focused on maintaining capital discipline
and driving meaningful free cash flow. We are executing our 2024 development plan with a tightened production guidance range of 152,000
to 154,000 boe/d (150,000 to 156,000 boe/d, previously). Our 2024 exploration and development expenditures guidance is unchanged at $1.2
to $1.3 billion.
We expect to generate approximately $700 million
of free cash flow(2)(4) in 2024, weighted 75% to H2/2024. We intend to allocate 50% of free cash flow to the balance sheet
and 50% to shareholder returns, which includes a combination of share buybacks and a quarterly dividend.
| (1) | Capital management measure. Refer to the Specified Financial Measures
section in this press release for further information. |
| (2) | Specified financial measure that does not
have any standardized meaning prescribed by IFRS and may not be comparable with the calculation
of similar measures presented by other entities. Refer to the Specified Financial Measures
section in this press release for further information. |
| (3) | Calculated in accordance with our amended
credit facilities agreement which is available on SEDAR+ at www.sedarplus.ca. |
| (4) | Based on the mid-point of 2024 production
and exploration and development expenditures guidance and the following full-year commodity
price assumptions: WTI - US$78.50/bbl; WCS differential - US$16/bbl; NYMEX Gas - US$2.30/MMbtu;
and Exchange Rate (CAD/USD) - 1.37. |
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
March 31, |
|
|
June 30, |
|
|
June 30, |
|
|
June 30, |
|
|
|
2024 |
|
|
2024 |
|
|
2023 |
|
|
2024 |
|
|
2023 |
|
FINANCIAL
(thousands of Canadian dollars, except per common share amounts) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum and natural gas sales |
|
$ |
1,133,123 |
|
|
$ |
984,192 |
|
|
$ |
598,760 |
|
|
$ |
2,117,315 |
|
|
$ |
1,154,096 |
|
Adjusted funds flow (1) |
|
|
532,839 |
|
|
|
423,846 |
|
|
|
273,590 |
|
|
|
956,685 |
|
|
|
510,579 |
|
Per share – basic |
|
|
0.65 |
|
|
|
0.52 |
|
|
|
0.47 |
|
|
|
1.17 |
|
|
|
0.90 |
|
Per share – diluted |
|
|
0.65 |
|
|
|
0.52 |
|
|
|
0.47 |
|
|
|
1.16 |
|
|
|
0.90 |
|
Free cash flow (2) |
|
|
180,673 |
|
|
|
(88 |
) |
|
|
96,313 |
|
|
|
180,585 |
|
|
|
94,395 |
|
Per share – basic |
|
|
0.22 |
|
|
|
— |
|
|
|
0.17 |
|
|
|
0.22 |
|
|
|
0.17 |
|
Per share – diluted |
|
|
0.22 |
|
|
|
— |
|
|
|
0.16 |
|
|
|
0.22 |
|
|
|
0.17 |
|
Cash flows from operating activities |
|
|
505,584 |
|
|
|
383,773 |
|
|
|
192,308 |
|
|
|
889,357 |
|
|
|
377,246 |
|
Per share – basic |
|
|
0.62 |
|
|
|
0.47 |
|
|
|
0.33 |
|
|
|
1.09 |
|
|
|
0.67 |
|
Per share – diluted |
|
|
0.62 |
|
|
|
0.47 |
|
|
|
0.33 |
|
|
|
1.08 |
|
|
|
0.66 |
|
Net income (loss) |
|
|
103,898 |
|
|
|
(14,043 |
) |
|
|
213,603 |
|
|
|
89,855 |
|
|
|
265,044 |
|
Per share – basic |
|
|
0.13 |
|
|
|
(0.02 |
) |
|
|
0.37 |
|
|
|
0.11 |
|
|
|
0.47 |
|
Per share – diluted |
|
|
0.13 |
|
|
|
(0.02 |
) |
|
|
0.36 |
|
|
|
0.11 |
|
|
|
0.47 |
|
Dividends declared |
|
|
18,161 |
|
|
|
18,494 |
|
|
|
— |
|
|
|
36,655 |
|
|
|
— |
|
Per share |
|
|
0.0225 |
|
|
|
0.0225 |
|
|
|
— |
|
|
|
0.0450 |
|
|
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and development expenditures |
|
$ |
339,573 |
|
|
$ |
412,551 |
|
|
$ |
170,704 |
|
|
$ |
752,124 |
|
|
$ |
404,330 |
|
Acquisitions and divestitures |
|
|
654 |
|
|
|
35,378 |
|
|
|
(112 |
) |
|
|
36,032 |
|
|
|
159 |
|
Total oil and natural gas capital expenditures |
|
$ |
340,227 |
|
|
$ |
447,929 |
|
|
$ |
170,592 |
|
|
$ |
788,156 |
|
|
$ |
404,489 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Debt |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Credit facilities |
|
$ |
625,976 |
|
|
$ |
849,926 |
|
|
$ |
986,903 |
|
|
$ |
625,976 |
|
|
$ |
986,903 |
|
Long-term notes |
|
|
1,881,894 |
|
|
|
1,637,155 |
|
|
|
1,601,468 |
|
|
|
1,881,894 |
|
|
|
1,601,468 |
|
Total debt (3) |
|
|
2,507,870 |
|
|
|
2,487,081 |
|
|
|
2,588,371 |
|
|
|
2,507,870 |
|
|
|
2,588,371 |
|
Working capital
deficiency (2) |
|
|
131,144 |
|
|
|
152,760 |
|
|
|
226,473 |
|
|
|
131,144 |
|
|
|
226,473 |
|
Net debt (1) |
|
$ |
2,639,014 |
|
|
$ |
2,639,841 |
|
|
$ |
2,814,844 |
|
|
$ |
2,639,014 |
|
|
$ |
2,814,844 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares Outstanding - basic (thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average |
|
|
814,151 |
|
|
|
821,710 |
|
|
|
583,365 |
|
|
|
817,931 |
|
|
|
564,319 |
|
End of period |
|
|
804,977 |
|
|
|
821,322 |
|
|
|
862,192 |
|
|
|
804,977 |
|
|
|
862,192 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BENCHMARK PRICES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI (US$/bbl) |
|
$ |
80.57 |
|
|
$ |
76.96 |
|
|
$ |
73.78 |
|
|
$ |
78.77 |
|
|
$ |
74.96 |
|
MEH oil (US$/bbl) |
|
|
83.10 |
|
|
|
78.95 |
|
|
|
75.01 |
|
|
|
81.03 |
|
|
|
76.22 |
|
MEH oil differential to WTI (US$/bbl) |
|
|
2.53 |
|
|
|
1.99 |
|
|
|
1.23 |
|
|
|
2.26 |
|
|
|
1.26 |
|
Edmonton par ($/bbl) |
|
|
105.30 |
|
|
|
92.16 |
|
|
|
95.13 |
|
|
|
98.73 |
|
|
|
97.09 |
|
Edmonton par differential to WTI (US$/bbl) |
|
|
(3.62 |
) |
|
|
(8.63 |
) |
|
|
(2.95 |
) |
|
|
(6.10 |
) |
|
|
(2.91 |
) |
WCS heavy oil ($/bbl) |
|
|
91.72 |
|
|
|
77.73 |
|
|
|
78.85 |
|
|
|
84.68 |
|
|
|
74.16 |
|
WCS differential to WTI (US$/bbl) |
|
|
(13.55 |
) |
|
|
(19.33 |
) |
|
|
(15.07 |
) |
|
|
(16.44 |
) |
|
|
(19.92 |
) |
Natural gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX (US$/MMbtu) |
|
$ |
1.89 |
|
|
$ |
2.24 |
|
|
$ |
2.10 |
|
|
$ |
2.07 |
|
|
$ |
2.76 |
|
AECO ($/Mcf) |
|
|
1.44 |
|
|
|
2.05 |
|
|
|
2.35 |
|
|
|
1.74 |
|
|
|
3.34 |
|
CAD/USD average exchange rate |
|
|
1.3684 |
|
|
|
1.3488 |
|
|
|
1.3431 |
|
|
|
1.3586 |
|
|
|
1.3475 |
|
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) | Calculated in accordance with our amended credit facilities agreement
which is available on SEDAR+ at www.sedarplus.ca. |
2 | Baytex Energy Corp. Second Quarter Report 2024 | |
| |
Three Months Ended | | |
Six Months Ended | |
| |
June 30, | | |
March 31, | | |
June 30, | | |
June 30, | | |
June 30, | |
| |
2024 | | |
2024 | | |
2023 | | |
2024 | | |
2023 | |
OPERATING | |
| | |
| | |
| | |
| | |
| |
Daily Production | |
| | | |
| | | |
| | | |
| | | |
| | |
Light oil and condensate (bbl/d) | |
| 67,031 | | |
| 66,036 | | |
| 35,322 | | |
| 66,534 | | |
| 33,510 | |
Heavy oil (bbl/d) | |
| 43,703 | | |
| 40,560 | | |
| 32,821 | | |
| 42,131 | | |
| 33,502 | |
NGL (bbl/d) | |
| 20,167 | | |
| 19,299 | | |
| 8,620 | | |
| 19,733 | | |
| 7,920 | |
Total liquids (bbl/d) | |
| 130,901 | | |
| 125,895 | | |
| 76,763 | | |
| 128,398 | | |
| 74,932 | |
Natural gas (Mcf/d) | |
| 139,764 | | |
| 148,353 | | |
| 77,989 | | |
| 144,059 | | |
| 80,017 | |
Oil equivalent
(boe/d @ 6:1) (1) | |
| 154,194 | | |
| 150,620 | | |
| 89,761 | | |
| 152,407 | | |
| 88,269 | |
| |
| | | |
| | | |
| | | |
| | | |
| | |
Netback (thousands of Canadian dollars) | |
| | | |
| | | |
| | | |
| | | |
| | |
Total sales, net of blending and other
expense (2) | |
$ | 1,065,438 | | |
$ | 919,984 | | |
$ | 545,765 | | |
$ | 1,985,422 | | |
$ | 1,041,420 | |
Royalties | |
| (240,440 | ) | |
| (209,171 | ) | |
| (107,920 | ) | |
| (449,611 | ) | |
| (201,173 | ) |
Operating expense | |
| (167,705 | ) | |
| (173,435 | ) | |
| (119,438 | ) | |
| (341,140 | ) | |
| (231,846 | ) |
Transportation expense | |
| (33,314 | ) | |
| (29,835 | ) | |
| (14,574 | ) | |
| (63,149 | ) | |
| (31,579 | ) |
Operating netback (2) | |
$ | 623,979 | | |
$ | 507,543 | | |
$ | 303,833 | | |
$ | 1,131,522 | | |
$ | 576,822 | |
General and administrative | |
| (21,006 | ) | |
| (22,412 | ) | |
| (15,240 | ) | |
| (43,418 | ) | |
| (26,974 | ) |
Cash financing and interest | |
| (53,946 | ) | |
| (53,280 | ) | |
| (28,255 | ) | |
| (107,226 | ) | |
| (46,630 | ) |
Realized financial derivatives (loss) gain | |
| (2,257 | ) | |
| 5,488 | | |
| 16,365 | | |
| 3,231 | | |
| 21,780 | |
Other (3) | |
| (13,931 | ) | |
| (13,493 | ) | |
| (3,113 | ) | |
| (27,424 | ) | |
| (14,419 | ) |
Adjusted funds
flow (4) | |
$ | 532,839 | | |
$ | 423,846 | | |
$ | 273,590 | | |
$ | 956,685 | | |
$ | 510,579 | |
| |
| | | |
| | | |
| | | |
| | | |
| | |
Netback (per boe) (2) | |
| | | |
| | | |
| | | |
| | | |
| | |
Total sales, net of blending and other
expense (2) | |
$ | 75.93 | | |
$ | 67.12 | | |
$ | 66.82 | | |
$ | 71.58 | | |
$ | 65.18 | |
Royalties (5) | |
| (17.14 | ) | |
| (15.26 | ) | |
| (13.21 | ) | |
| (16.21 | ) | |
| (12.59 | ) |
Operating expense (5) | |
| (11.95 | ) | |
| (12.65 | ) | |
| (14.62 | ) | |
| (12.30 | ) | |
| (14.51 | ) |
Transportation
expense (5) | |
| (2.37 | ) | |
| (2.18 | ) | |
| (1.78 | ) | |
| (2.28 | ) | |
| (1.98 | ) |
Operating netback (2) | |
$ | 44.47 | | |
$ | 37.03 | | |
$ | 37.21 | | |
$ | 40.79 | | |
$ | 36.10 | |
General and administrative (5) | |
| (1.50 | ) | |
| (1.64 | ) | |
| (1.87 | ) | |
| (1.57 | ) | |
| (1.69 | ) |
Cash financing and interest (5) | |
| (3.84 | ) | |
| (3.89 | ) | |
| (3.46 | ) | |
| (3.87 | ) | |
| (2.92 | ) |
Realized financial derivatives (loss)
gain (5) | |
| (0.16 | ) | |
| 0.40 | | |
| 2.00 | | |
| 0.12 | | |
| 1.36 | |
Other (3) | |
| (1.00 | ) | |
| (0.98 | ) | |
| (0.39 | ) | |
| (0.98 | ) | |
| (0.89 | ) |
Adjusted funds flow
(4) | |
$ | 37.97 | | |
$ | 30.92 | | |
$ | 33.49 | | |
$ | 34.49 | | |
$ | 31.96 | |
Notes:
| (1) | Barrel of oil equivalent (“boe”) amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to
one barrel of oil. The use of boe amounts may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand
cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner
tip and does not represent a value equivalency at the wellhead. |
| (2) | Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation
of similar measures presented by other entities. Refer to the Specified Financial Measures section in this press release for further information. |
| (3) | Other is comprised of realized foreign exchange gain or loss, other income or expense, current income tax expense or recovery and
cash share-based compensation. Refer to the Q2/2024 MD&A for further information on these amounts. |
| (4) | Capital management measure. Refer to the Specified Financial Measures section in this press release for further information. |
| (5) | Calculated as royalties, operating, transportation expense, general and administrative expense, cash interest expense or realized
financial derivatives gain or loss divided by barrels of oil equivalent production volume for the applicable period. |
| Baytex Energy Corp. Second Quarter Report 2024 | 3 |
During the second quarter, we delivered operating and financial results
consistent with our full-year guidance. We remain committed to a disciplined, returns-based capital allocation philosophy intended to
drive increased per-share returns. Our strong free cash flow forecast for 2024 reflects our stable production profile and the efficiency
of our exploration and development program.
We increased production per basic share by 23%
in Q2/2024, compared to Q2/2023, with production averaging 154,194 boe/d (85% oil and NGLs). Adjusted funds flow(1) was
$533 million or $0.65 per basic share, 38% higher than $0.47 per basic share in Q2/2023, and we generated net income of $104 million ($0.13
per basic share). Exploration and development expenditures totaled $340 million and we brought 58 (39.8 net) wells onstream.
During the second quarter we generated free cash
flow(2) of $181 million ($0.22 per basic share) and returned $97 million to shareholders. We repurchased 16.4 million
common shares for $79 million, at an average price of $4.84 per share, and paid a quarterly cash dividend of $18 million ($0.0225 per
share).
During the last twelve months, we returned $378
million to shareholders. We repurchased 57.5 million common shares for $304 million, representing 6.7% of our shares outstanding, at an
average price of $5.28 per share, and paid total dividends of $74 million ($0.09 per share).
On June 26, 2024, we renewed our Normal Course
Issuer Bid ("NCIB") with the Toronto Stock Exchange for a share buyback program for up to 10% of our public float. The renewed
NCIB allows Baytex to purchase up to 70 million common shares during the 12-month period commencing July 2, 2024 and ending July 1,
2025. For the period July 2, 2024 to July 25, 2024, we repurchased 4.8 million common shares for $24 million, at an average
price of $5.00 per share.
During the second quarter, we extended our debt
maturities and increased the liquidity on our credit facilities. On April 1, 2024, we closed a private placement offering of US$575
million aggregate principal amount of senior unsecured notes. The notes bear interest at a rate of 7.375% per annum and mature on March 15,
2032. Net proceeds from the offering were used to redeem US$409.8 million aggregate principal amount of outstanding 8.75% notes and the
associated call premiums and repay a portion of the debt outstanding on our credit facilities. In addition, on May 9, 2024, we extended
the maturity of our US$1.1 billion credit facilities to May 2028.
Our total debt(3) at June 30,
2024 was $2.5 billion, largely unchanged from year-end 2023. Continuing to strengthen our balance sheet remains a priority. Based on our
forecast free cash flow and shareholder return profile, we expect a reduction in total debt in the second half of 2024. The change in
our total debt year-to-date reflects the strengthening U.S. dollar, relative to the Canadian dollar, on our U.S. dollar denominated debt
(approximately $70 million), the call premium and issuance costs on our private placement offering and debt refinancing (approximately
$50 million), and strategic land acquisitions (approximately $35 million). We are now forecasting interest expense for 2024 of $200 million,
up from $190 million, previously.
We employ a disciplined commodity hedging program
to help mitigate the volatility in revenue due to changes in commodity prices. For the second half of 2024, we have entered into hedges
on approximately 40% of our net crude oil exposure utilizing two-way collars with an average floor price of US$60/bbl and an average ceiling
price of US$93/bbl. For H1/2025, we have entered into hedges on approximately 35% of our net crude oil exposure utilizing two-way collars
with an average floor price of US$60/bbl and an average ceiling price of US$91/bbl. A complete listing of our financial derivative contracts
can be found in Note 17 to our Q2/2024 financial statements.
Operations
In the Eagle Ford, we continue to deliver strong
results across the black oil, volatile oil and condensate windows of our acreage. We generated production of 90,506 boe/d (82% oil and
NGL) in Q2/2024. During the second quarter, we brought 11 (10.7 net) operated Lower Eagle Ford wells onstream that were largely focused
on the black oil window. We brought onstream one of our strongest performing oil-weighted pads to-date (3-wells, Pluto A1H, B2H and D4H)
with the wells generating an average 30-day peak production rate of 1,348 boe/d per well (1,161 bbl/d of crude oil, 104 bbl/d of NGLs,
500 Mcf/d of natural gas).
In aggregate, 8 of 11 wells brought onstream during
the second quarter were on production for a sufficient amount of time to establish 30-day peak production rates. These wells generated
an average 30-day peak production rate of 1,022 boe/d per well (892 bbl/d of crude oil, 72 bbl/d of NGLs, 349 Mcf/d of natural gas). Due
to efficient drilling and completion activities, in the first half of 2024 we realized an 8% improvement in operated drilling and completion
costs per completed lateral foot over 2023. On our non-operated Eagle Ford acreage, we brought 19 (4.1 net) wells onstream.
| (1) | Capital management measure. Refer to the Specified Financial Measures
section in this press release for further information. |
| (2) | Specified financial measure that does not
have any standardized meaning prescribed by IFRS and may not be comparable with the calculation
of similar measures presented by other entities. Refer to the Specified Financial Measures
section in this press release for further information. |
| (3) | Calculated in accordance with our amended
credit facilities agreement which is available on SEDAR+ at www.sedarplus.ca. |
4 | Baytex Energy Corp. Second Quarter Report 2024 | |
We are focused on optimizing our acreage and continue
to identify Upper Eagle Ford development areas. Our 2024 program includes four Upper Eagle Ford wells. The first three wells were brought
onstream in Q1/2024 and continue to deliver strong results. The fourth well was brought onstream in July. In addition, following our successful
Q1/2024 Lower Eagle Ford refrac (Medina Unit 3H), we are evaluating additional refrac opportunities to supplement our 2025 capital program.
In our Canadian light oil business unit, the first
pad (3-wells) from our 2024 Duvernay program was brought onstream in May and generated an average 30-day peak production rate of
1,350 boe/d per well (890 bbl/d of crude oil, 326 bbl/d of NGLs, 825 Mcf/d of natural gas). These initial results are consistent with
expectations. The second pad (4-wells) is expected to be onstream in August. In the Viking, activity resumed in late June following
spring breakup.
In our heavy oil business unit, second quarter
activity is typically lower due to spring breakup. Peavine continued to outperform expectations with production averaging 19,938 bbl/d
(100% heavy oil) during the second quarter, up 13% from Q1/2024. In Q2/2024, we brought 4 (4.0 net) wells onstream at Peavine that generated
an average 30-day peak production rate of 760 bbl/ d per well (100% heavy oil). Following spring breakup, our heavy oil development program
has ramped up with four rigs running across our Peavine, Peace River and Lloydminster regions.
Quarterly Dividend
The Board of Directors declared a quarterly cash
dividend of $0.0225 per share to be paid on October 1, 2024 to shareholders of record on September 16, 2024.
2023 ESG Report
On June 20, 2024, the Canadian government
passed amendments to the Competition Act that creates uncertainty for companies that wish to publicly communicate their environmental
goals, targets and performance. As it is unclear how the new law will be interpreted and enforced, and given the significant potential
penalties associated with non-compliance, we have deferred the publication of our 2023 ESG report.
This legislation does not change our commitment
to our environmental goals and to ensuring safe, responsible operations. We are proud of the work we have done with respect to GHG emissions
and air quality, asset retirement, reclamation and water management. We remain committed to moving these items forward.
As more guidance regarding the implementation of this new law becomes
available, we look forward to sharing our progress.
Additional Information
Our condensed consolidated interim unaudited
financial statements for the three and six months ended June 30, 2024 and the related Management's Discussion and Analysis of the
operating and financial results can be accessed on our website at www.baytexenergy.com and will be available shortly through SEDAR+ at
www.sedarplus.ca and EDGAR at www.sec.gov/edgar.shtml.
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: our expectation that free cash flow will increase in the second half of 2024 allowing for increased
shareholder returns and debt reduction; for 2024: our guidance for exploration and development expenditures and production, the amount
of free cash flow we expect to generate based on the forward strip and our expected allocation of that free cash flow as between the balance
sheet and shareholder returns (including share buybacks and quarterly dividends); that we are committed to a disciplined, returns-based
capital allocation philosophy to drive increased per-share returns; our expectation that we will reduce our total debt during H2/2024;
our forecast interest rate expense for 2024; our commodity hedging program, the percentage of our 2024 net crude exposure that is hedged,
and the ability of such program to mitigate revenue volatility due to changes in commodity prices; well completion plans for the Duvernay;
and that we will share progress with respect to ESG matters. In addition, information and statements relating to reserves are deemed to
be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described
exist in quantities predicted or estimated, and that they can be profitably produced in the future.
| Baytex Energy Corp. Second Quarter Report 2024 | 5 |
These forward-looking statements are based
on certain key assumptions regarding, among other things: oil and natural gas prices and differentials between light, medium and heavy
crude oil prices; well production rates and reserve volumes; success obtained in drilling new wells; our ability to add production and
reserves through our exploration and development activities; capital expenditure levels; operating costs; our ability to borrow under
our credit agreements; the receipt, in a timely manner, of regulatory and other required approvals for our operating activities; the availability
and cost of labour and other industry services; interest and foreign exchange rates; the continuance of existing and, in certain circumstances,
proposed tax and royalty regimes; our ability to develop our crude oil and natural gas properties in the manner currently contemplated;
our ability to market oil and natural gas successfully; that we will have sufficient financial resources in the future to provide shareholder
returns; and current industry conditions, laws and regulations continuing in effect (or, where changes are proposed, such changes being
adopted as anticipated). Readers are cautioned that such assumptions, although considered reasonable by Baytex at the time of preparation,
may prove to be incorrect.
Actual results achieved will vary from the
information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include,
but are not limited to: the risk of an extended period of low oil and natural gas prices; risks associated with our ability to develop
our properties and add reserves; that we may not achieve the expected benefits of acquisitions and we may sell assets below their carrying
value; the availability and cost of capital or borrowing; restrictions or costs imposed by climate change initiatives and the physical
risks of climate change; the impact of an energy transition on demand for petroleum productions; availability and cost of gathering, processing
and pipeline systems; retaining or replacing our leadership and key personnel; changes in income tax or other laws or government incentive
programs; risks associated with large projects; risks associated with higher a higher concentration of activity and tighter drilling spacing;
costs to develop and operate our properties; risks associated with achieving our total debt target, production guidance, exploration and
development expenditures guidance; the amount of free cash flow we expect to generate; risk that the board of directors determines to
allocate capital other than as set forth herein; current or future controls, legislation or regulations; restrictions on or access to
water or other fluids; public perception and its influence on the regulatory regime; new regulations on hydraulic fracturing; regulations
regarding the disposal of fluids; risks associated with our hedging activities; variations in interest rates and foreign exchange rates;
uncertainties associated with estimating oil and natural gas reserves; our inability to fully insure against all risks; risks associated
with a third-party operating our Eagle Ford properties; additional risks associated with our thermal heavy crude oil projects; our ability
to compete with other organizations in the oil and gas industry; risk that we do not achieve our GHG emissions intensity reduction target;
risks associated with our use of information technology systems; adverse results of litigation; that our Credit Facilities may not provide
sufficient liquidity or may not be renewed; failure to comply with the covenants in our debt agreements; risks associated with expansion
into new activities; the impact of Indigenous claims; risks of counterparty default; impact of geopolitical risk and conflicts; loss of
foreign private issuer status; conflicts of interest between the Corporation and its directors and officers; variability of share buybacks
and dividends; risks associated with the ownership of our securities, including changes in market-based factors; risks for United States
and other non-resident shareholders, including the ability to enforce civil remedies, differing practices for reporting reserves and production,
additional taxation applicable to non-residents and foreign exchange risk; and other factors, many of which are beyond our control. Readers
are cautioned that the foregoing list of risk factors is not exhaustive. New risk factors emerge from time to time, and it is not possible
for management to predict all of such factors and to assess in advance the impact of each such factor on our business or the extent to
which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking
statements.
These and additional risk factors are discussed
in our Annual Information Form, Annual Report on Form 40-F and Management's Discussion and Analysis for the year ended December 31,
2023 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.
This press release contains information that
may be considered a financial outlook under applicable securities laws about the Corporation's potential financial position, including,
but not limited to, our 2024 guidance for development expenditures; our expected 2024 free cash flow; and our intentions regarding the
allocating our annual free cash flow; all of which are subject to numerous assumptions, risk factors, limitations and qualifications,
including those set forth in the above paragraphs. The actual results of operations of the Corporation and the resulting financial results
will vary from the amounts set forth in this 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, the Corporation undertakes no obligation to update such financial outlook,
whether as a result of new information, future events or otherwise. The financial outlook contained in this press release was made as
of the date of this press release and was provided for the purpose of providing further information about the Corporation's potential
future business operations. Readers are cautioned that the financial outlook contained in this press release is not conclusive and is
subject to change.
The future acquisition of our common shares
pursuant to a share buyback (including through its NCIB), if any, and the level thereof is uncertain. Any decision to acquire Common Shares
pursuant to a share buyback will be subject to the discretion of the Board and may depend on a variety of factors, including, without
limitation, the Corporation's business performance, financial condition, financial requirements, growth plans, expected capital requirements
and other conditions existing at such future time including, without limitation, contractual restrictions (including covenants contained
in the agreements governing any indebtedness that the Corporation has incurred or may incur in the future, including the terms of the
Credit Facilities) and satisfaction of the solvency tests imposed on the Corporation under applicable corporate law. There can be no assurance
of the number of Common Shares that the Corporation will acquire pursuant to a share buyback, if any, in the future.
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 and any
special dividends) 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.
All amounts in this press release are stated in Canadian dollars
unless otherwise specified.
6 | Baytex Energy Corp. Second Quarter Report 2024 | |
Specified Financial Measures
In this press release, we refer to certain
financial measures (such as free cash flow, operating netback, working capital deficiency, average royalty rate and total sales, net of
blending and other expense) which do not have any standardized meaning prescribed by IFRS. While these measures are commonly used in the
oil and gas industry, our determination of these measures may not be comparable with calculations of similar measures presented by other
reporting issuers. This press release also contains the terms "adjusted funds flow" and "net debt" which are considered
capital management measures. We believe that inclusion of these specified financial measures provides useful information to financial
statement users when evaluating the financial results of Baytex.
Non-GAAP Financial Measures
Total sales, net of blending and other expense
Total sales, net of blending and other expense
represents the revenues realized from produced volumes during a period. Total sales, net of blending and other expense is comprised of
total petroleum and natural gas sales adjusted for blending and other expense. We believe including the blending and other expense associated
with purchased volumes is useful when analyzing our realized pricing for produced volumes against benchmark commodity prices.
Operating netback
Operating netback 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.
The following table reconciles total sales, net of blending and
other expense and operating netback to petroleum and natural gas sales.
| |
Three Months Ended | | |
Six Months Ended | |
| |
June 30, | | |
March 31, | | |
June 30, | | |
June 30, | | |
June 30, | |
($ thousands) | |
2024 | | |
2024 | | |
2023 | | |
2024 | | |
2023 | |
Petroleum and natural gas sales | |
$ | 1,133,123 | | |
$ | 984,192 | | |
$ | 598,760 | | |
$ | 2,117,315 | | |
$ | 1,154,096 | |
Blending and other expense | |
| (67,685 | ) | |
| (64,208 | ) | |
| (52,995 | ) | |
| (131,893 | ) | |
| (112,676 | ) |
Total sales, net of blending and other expense | |
$ | 1,065,438 | | |
$ | 919,984 | | |
$ | 545,765 | | |
$ | 1,985,422 | | |
$ | 1,041,420 | |
Royalties | |
| (240,440 | ) | |
| (209,171 | ) | |
| (107,920 | ) | |
| (449,611 | ) | |
| (201,173 | ) |
Operating expense | |
| (167,705 | ) | |
| (173,435 | ) | |
| (119,438 | ) | |
| (341,140 | ) | |
| (231,846 | ) |
Transportation expense | |
| (33,314 | ) | |
| (29,835 | ) | |
| (14,574 | ) | |
| (63,149 | ) | |
| (31,579 | ) |
Operating netback | |
$ | 623,979 | | |
$ | 507,543 | | |
$ | 303,833 | | |
$ | 1,131,522 | | |
$ | 576,822 | |
Realized financial derivatives (loss)
gain (1) | |
| (2,257 | ) | |
| 5,488 | | |
| 16,365 | | |
| 3,231 | | |
| 21,780 | |
Operating netback after realized financial derivatives | |
$ | 621,722 | | |
$ | 513,031 | | |
$ | 320,198 | | |
$ | 1,134,753 | | |
$ | 598,602 | |
(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, 2024 and the consolidated financial statements for the three months
ended March 31, 2024 for further information. |
Free cash flow
We use free cash flow to evaluate our financial
performance and to assess the cash available for debt repayment, common share repurchases, dividends and acquisition opportunities. Free
cash flow is comprised of cash flows from operating activities adjusted for changes in non-cash working capital, additions to exploration
and evaluation assets, additions to oil and gas properties, payments on lease obligations, transaction costs and cash premiums on derivatives.
Free cash flow is reconciled to cash flows from operating activities
in the following table.
| |
Three Months Ended | | |
Six Months Ended | |
| |
June 30, | | |
March 31, | | |
June 30, | | |
June 30, | | |
June 30, | |
($ thousands) | |
2024 | | |
2024 | | |
2023 | | |
2024 | | |
2023 | |
Cash flows from operating activities | |
$ | 505,584 | | |
$ | 383,773 | | |
$ | 192,308 | | |
$ | 889,357 | | |
$ | 377,246 | |
Change in non-cash working capital | |
| 20,140 | | |
| 32,023 | | |
| 40,795 | | |
| 52,163 | | |
| 79,849 | |
Additions to exploration and evaluation assets | |
| — | | |
| — | | |
| (741 | ) | |
| — | | |
| (1,231 | ) |
Additions to oil and gas properties | |
| (339,573 | ) | |
| (412,551 | ) | |
| (169,963 | ) | |
| (752,124 | ) | |
| (403,099 | ) |
Payments on lease obligations | |
| (5,478 | ) | |
| (4,872 | ) | |
| (1,181 | ) | |
| (10,350 | ) | |
| (2,336 | ) |
Transaction costs | |
| — | | |
| 1,539 | | |
| 32,832 | | |
| 1,539 | | |
| 41,703 | |
Cash premiums on derivatives | |
| — | | |
| — | | |
| 2,263 | | |
| — | | |
| 2,263 | |
Free cash flow | |
$ | 180,673 | | |
$ | (88 | ) | |
$ | 96,313 | | |
$ | 180,585 | | |
$ | 94,395 | |
| Baytex Energy Corp. Second Quarter Report 2024 | 7 |
Working capital deficiency
Working capital deficiency is calculated as
cash, trade receivables, prepaids and other assets net of trade payables, dividends payable, other long-term liabilities and share-based
compensation liability. Working capital deficiency is used by management to measure the Company's liquidity. At June 30, 2024, the
Company had $874.9 million of available credit facility capacity to cover any working capital deficiencies.
The following table summarizes the calculation of working capital
deficiency.
| |
As at | |
($ thousands) | |
June 30, 2024 | | |
March 31, 2024 | | |
December 31, 2023 | |
Cash | |
$ | (35,887 | ) | |
$ | (29,140 | ) | |
$ | (55,815 | ) |
Trade receivables | |
| (429,098 | ) | |
| (423,119 | ) | |
| (339,405 | ) |
Prepaids and other assets | |
| (81,805 | ) | |
| (77,901 | ) | |
| (83,259 | ) |
Trade payables | |
| 617,222 | | |
| 626,137 | | |
| 477,295 | |
Share-based compensation liability | |
| 22,706 | | |
| 18,667 | | |
| 35,732 | |
Other long-term liabilities | |
| 19,845 | | |
| 19,622 | | |
| 19,147 | |
Dividends payable | |
| 18,161 | | |
| 18,494 | | |
| 18,381 | |
Working capital deficiency | |
$ | 131,144 | | |
$ | 152,760 | | |
$ | 72,076 | |
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
(a non-GAAP financial measure). The actual royalty rates can vary for a number of reasons, including the commodity produced, royalty contract
terms, commodity price level, royalty incentives and the area or jurisdiction.
Operating netback per boe
Operating netback per boe is equal to operating
netback (a non-GAAP financial measure) divided by barrels of oil equivalent sales volume for the applicable period and is used to assess
our operating performance on a unit of production basis.
Capital Management Measures
Net debt
We use net debt to monitor our current financial
position and to evaluate existing sources of liquidity. We also use net debt projections to estimate future liquidity and whether additional
sources of capital are required to fund ongoing operations. Net debt is comprised of our credit facilities and long-term notes outstanding
adjusted for unamortized debt issuance costs, trade payables, share-based compensation liability, dividends payable, other long-term
liabilities, cash, trade receivables, and prepaids and other assets.
8 | Baytex Energy Corp. Second Quarter Report 2024 | |
The following table summarizes our calculation of net debt.
| |
As at | |
($ thousands) | |
June 30, 2024 | | |
March 31, 2024 | | |
December 31, 2023 | |
Credit facilities | |
$ | 607,589 | | |
$ | 835,363 | | |
$ | 848,749 | |
Unamortized debt issuance costs - Credit facilities (1) | |
| 18,387 | | |
| 14,563 | | |
| 15,987 | |
Long-term notes | |
| 1,833,182 | | |
| 1,602,417 | | |
| 1,562,361 | |
Unamortized debt issuance costs - Long-term notes (1) | |
| 48,712 | | |
| 34,738 | | |
| 35,114 | |
Trade payables | |
| 617,222 | | |
| 626,137 | | |
| 477,295 | |
Share-based compensation liability | |
| 22,706 | | |
| 18,667 | | |
| 35,732 | |
Other long-term liabilities | |
| 19,845 | | |
| 19,622 | | |
| 19,147 | |
Dividends payable | |
| 18,161 | | |
| 18,494 | | |
| 18,381 | |
Cash | |
| (35,887 | ) | |
| (29,140 | ) | |
| (55,815 | ) |
Trade receivables | |
| (429,098 | ) | |
| (423,119 | ) | |
| (339,405 | ) |
Prepaids and other assets | |
| (81,805 | ) | |
| (77,901 | ) | |
| (83,259 | ) |
Net debt | |
$ | 2,639,014 | | |
$ | 2,639,841 | | |
$ | 2,534,287 | |
(1) | Unamortized debt issuance costs
for the respective periods 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, 2024 and the consolidated financial statements for the three months ended
March 31, 2024. |
Adjusted funds flow
Adjusted funds flow is used to monitor operating performance and
our ability to generate funds for exploration and development expenditures and settlement of abandonment obligations. Adjusted funds flow
is comprised of cash flows from operating activities adjusted for changes in non-cash working capital, asset retirement obligations settled,
transaction costs and cash premiums on derivatives during the applicable period.
Adjusted funds flow is reconciled to amounts disclosed in the primary
financial statements in the following table.
| |
Three Months Ended | | |
Six Months Ended | |
($ thousands) | |
June 30,
2024 | | |
March 31,
2024 | | |
June 30,
2023 | | |
June 30,
2024 | | |
June 30,
2023 | |
Cash flow from operating activities | |
$ | 505,584 | | |
$ | 383,773 | | |
$ | 192,308 | | |
$ | 889,357 | | |
$ | 377,246 | |
Change in non-cash working capital | |
| 20,140 | | |
| 32,023 | | |
| 40,795 | | |
| 52,163 | | |
| 79,849 | |
Asset retirement obligations settled | |
| 7,115 | | |
| 6,511 | | |
| 5,392 | | |
| 13,626 | | |
| 9,518 | |
Transaction costs | |
| — | | |
| 1,539 | | |
| 32,832 | | |
| 1,539 | | |
| 41,703 | |
Cash premiums on derivatives | |
| — | | |
| — | | |
| 2,263 | | |
| — | | |
| 2,263 | |
Adjusted funds flow | |
$ | 532,839 | | |
$ | 423,846 | | |
$ | 273,590 | | |
$ | 956,685 | | |
$ | 510,579 | |
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 peak 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.
| Baytex Energy Corp. Second Quarter Report 2024 | 9 |
Throughout this press release, “oil
and NGL” refers to heavy crude oil, bitumen, light and medium crude 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, 2024. 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, 2024 | |
Three Months Ended June 30, 2023 | |
| |
| |
Light | |
| |
| |
| |
| |
Light | |
| |
| |
| |
| |
| |
and | |
| |
| |
| |
| |
and | |
| |
| |
| |
| |
Heavy | |
Medium | |
| |
Natural | |
Oil | |
Heavy | |
Medium | |
| |
Natural | |
Oil | |
| |
Crude Oil | |
Crude
Oil | |
NGL | |
Gas | |
Equivalent | |
Crude Oil | |
Crude
Oil | |
NGL | |
Gas | |
Equivalent | |
| |
(bbl/d) | |
(bbl/d) | |
(bbl/d) | |
(Mcf/d) | |
(boe/d) | |
(bbl/d) | |
(bbl/d) | |
(bbl/d) | |
(Mcf/d) | |
(boe/d) | |
Canada – Heavy | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
Peace
River | |
| 9,116 | |
| 7 | |
| 41 | |
| 10,733 | |
| 10,953 | |
| 9,801 | |
| 6 | |
| 49 | |
| 11,117 | |
| 11,708 | |
Lloydminster | |
| 13,688 | |
| 16 | |
| — | |
| 1,607 | |
| 13,972 | |
| 11,398 | |
| 23 | |
| — | |
| 1,228 | |
| 11,625 | |
Peavine | |
| 19,938 | |
| — | |
| — | |
| — | |
| 19,938 | |
| 11,622 | |
| — | |
| — | |
| — | |
| 11,622 | |
| |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
Canada - Light | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
Viking | |
| — | |
| 8,130 | |
| 181 | |
| 10,586 | |
| 10,075 | |
| — | |
| 13,265 | |
| 181 | |
| 12,105 | |
| 15,464 | |
Duvernay | |
| — | |
| 2,509 | |
| 1,640 | |
| 5,875 | |
| 5,128 | |
| — | |
| 675 | |
| 566 | |
| 1,946 | |
| 1,565 | |
Remaining
Properties | |
| 961 | |
| 414 | |
| 447 | |
| 10,798 | |
| 3,622 | |
| — | |
| 643 | |
| 638 | |
| 15,647 | |
| 3,890 | |
| |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
United States | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
Eagle
Ford | |
| — | |
| 55,955 | |
| 17,858 | |
| 100,165 | |
| 90,506 | |
| — | |
| 20,710 | |
| 7,186 | |
| 35,946 | |
| 33,887 | |
Total | |
| 43,703 | |
| 67,031 | |
| 20,167 | |
| 139,764 | |
| 154,194 | |
| 32,821 | |
| 35,322 | |
| 8,620 | |
| 77,989 | |
| 89,761 | |
| |
Six Months Ended June 30, 2024 | |
Six Months Ended June 30, 2023 | |
| |
| |
Light | |
| |
| |
| |
| |
Light | |
| |
| |
| |
| |
| |
and | |
| |
| |
| |
| |
and | |
| |
| |
| |
| |
Heavy | |
Medium | |
| |
Natural | |
Oil | |
Heavy | |
Medium | |
| |
Natural | |
Oil | |
| |
Crude Oil | |
Crude Oil | |
NGL | |
Gas | |
Equivalent | |
Crude Oil | |
Crude Oil | |
NGL | |
Gas | |
Equivalent | |
| |
(bbl/d) | |
(bbl/d) | |
(bbl/d) | |
(Mcf/d) | |
(boe/d) | |
(bbl/d) | |
(bbl/d) | |
(bbl/d) | |
(Mcf/d) | |
(boe/d) | |
Canada – Heavy | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
Peace
River | |
| 9,299 | |
| 8 | |
| 44 | |
| 10,411 | |
| 11,086 | |
| 10,289 | |
| 9 | |
| 51 | |
| 11,191 | |
| 12,215 | |
Lloydminster | |
| 13,422 | |
| 15 | |
| — | |
| 1,519 | |
| 13,690 | |
| 11,522 | |
| 17 | |
| — | |
| 1,223 | |
| 11,743 | |
Peavine | |
| 18,768 | |
| — | |
| — | |
| — | |
| 18,768 | |
| 11,691 | |
| — | |
| — | |
| — | |
| 11,691 | |
| |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
Canada - Light | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
Viking | |
| — | |
| 8,655 | |
| 185 | |
| 10,827 | |
| 10,645 | |
| — | |
| 13,948 | |
| 187 | |
| 11,864 | |
| 16,113 | |
Duvernay | |
| — | |
| 2,156 | |
| 1,699 | |
| 5,665 | |
| 4,799 | |
| — | |
| 868 | |
| 754 | |
| 2,283 | |
| 2,002 | |
Remaining
Properties | |
| 642 | |
| 451 | |
| 542 | |
| 13,568 | |
| 3,896 | |
| — | |
| 658 | |
| 661 | |
| 19,001 | |
| 4,485 | |
| |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
United States | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
Eagle
Ford | |
| — | |
| 55,249 | |
| 17,263 | |
| 102,069 | |
| 89,523 | |
| — | |
| 18,010 | |
| 6,267 | |
| 34,455 | |
| 30,020 | |
Total | |
| 42,131 | |
| 66,534 | |
| 19,733 | |
| 144,059 | |
| 152,407 | |
| 33,502 | |
| 33,510 | |
| 7,920 | |
| 80,017 | |
| 88,269 | |
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 & Investor
Relations
Toll Free Number: 1-800-524-5521
Email: investor@baytexenergy.com
10 | Baytex Energy Corp. Second Quarter Report 2024 | |
BAYTEX ENERGY CORP.
Management’s Discussion and Analysis
For the three and six months ended June 30, 2024 and 2023
Dated July 25, 2024
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, 2024. This information is provided as of July 25, 2024. In this MD&A, references to “Baytex”, the
“Company”, “we”, “us” and “our” and similar terms refer to Baytex Energy Corp. and its
subsidiaries on a consolidated basis, except where the context requires otherwise. The results for the three and six months ended June 30,
2024 ("Q2/2024" and "YTD 2024") have been compared with the results for the three and six months ended June 30,
2023 ("Q2/2023" and "YTD 2023"). This MD&A should be read in conjunction with the Company’s unaudited condensed
consolidated interim financial statements (“consolidated financial statements”) for the three and six months ended June 30,
2024, its audited comparative consolidated financial statements for the years ended December 31, 2023 and 2022, together with the
accompanying notes, and its Annual Information Form ("AIF") for the year ended December 31, 2023. These documents
and additional information about Baytex are accessible on the SEDAR+ website at www.sedarplus.ca 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
oil and gas company based in Calgary, Alberta. The Company operates in Canada and the United States ("U.S."). The Canadian operating
segment includes our light oil assets in the Viking and Duvernay, our heavy oil assets in Peace River and Lloydminster and our conventional
oil and natural gas assets in Western Canada. The U.S. operating segment includes our Eagle Ford operated and non-operated assets in Texas.
On June 20, 2023, Baytex and Ranger Oil Corporation
("Ranger") completed a merger of the two companies (the "Merger") whereby Baytex acquired all of the issued and outstanding
common shares of Ranger. The Merger increased our Eagle Ford scale and provided an operating platform to effectively allocate capital
across the Western Canadian Sedimentary Basin and the Eagle Ford. Production from the Ranger assets is approximately 80% weighted towards
high netback light oil and liquids and is primarily operated which increased our ability to effectively allocate capital.
We issued 311.4 million common shares, paid $732.8
million in cash and assumed $1.1 billion of Ranger's net debt(1). The cash portion of the transaction was funded with an expanded
US$1.1 billion credit facility, a US$150 million two-year term loan facility (which was fully repaid and cancelled in August 2023)
and the net proceeds from the issuance of US$800 million senior unsecured notes due 2030.
SECOND QUARTER HIGHLIGHTS
Baytex delivered strong operating and financial
results in Q2/2024. Production of 154,194 boe/d for Q2/2024 reflects our successful development programs in the U.S. and Canada. We invested
$339.6 million on exploration and development expenditures and generated free cash flow(2) of $180.7 million.
(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. |
| Baytex Energy Corp. Second Quarter Report 2024 | 11 |
Exploration and development expenditures totaled
$339.6 million in Q2/2024. In the U.S. we invested $237.7 million and production averaged 90,506 boe/d during Q2/2024 compared to exploration
and development expenditures of $74.3 million and production of 33,887 boe/d for Q2/2023. The increase in U.S. exploration and development
spending and production in Q2/2024 relative to Q2/2023 is primarily the result of the Merger. In Canada, we invested $101.9 million in
Q2/2024 and generated production of 63,688 boe/d in Q2/2024 compared to exploration and development expenditures of $96.4 million and
production of 55,874 boe/d in Q2/2023 which reflects our successful light and heavy oil development program.
Oil prices improved during Q2/2024 as a result
of stable supply and demand, continued OPEC production curtailments and geopolitical tension. The WTI benchmark price for Q2/2024 was
US$80.57/bbl which was higher than Q2/2023 when WTI averaged US$73.78/bbl. Adjusted funds flow(1) of $532.8 million and
cash flows from operating activities of $505.6 million for Q2/2024 reflect higher production compared to Q2/2023 when we generated adjusted
funds flow of $273.6 million and cash flows from operating activities of $192.3 million.
Net debt(1) of $2.6 billion at
June 30, 2024 was consistent with $2.5 billion at December 31, 2023 which was due to the impact of a weaker Canadian dollar
at June 30, 2024 on our U.S. dollar denominated debt and also reflects $38.8 million of property acquisitions along with $49.7 million
of debt issuance costs incurred during YTD 2024. We expect net debt to decline over the remainder of 2024 as we continue to allocate
50% of free cash flow to the balance sheet.
| (1) | Capital
management measure. Refer to the Specified Financial Measures section in this MD&A for
further information. |
2024 GUIDANCE
Our 2024 annual guidance has been revised with
a tightened production guidance range of 152,000 - 154,000 boe/d. We are now forecasting interest expense for 2024 of $200 million ($3.57/boe),
up from $190 million ($3.40/boe), previously. Our annual exploration and development expenditures guidance is unchanged at $1.2 - $1.3
billion.
| |
Previous
Annual
Guidance (1) | |
Revised Annual
Guidance | |
YTD 2024 Results |
Exploration and development expenditures | |
$1.2 - $1.3 billion | |
No change | |
$752.1 million |
Production (boe/d) | |
150,000 - 156,000 | |
152,000 - 154,000 | |
152,407 |
Expenses: | |
| |
| |
|
Average royalty rate (2) | |
23% | |
No change | |
22.6% |
Operating (3) | |
$11.25 - $12.00/boe | |
No change | |
$12.30/boe |
Transportation (3) | |
$2.35 - $2.55/boe | |
No change | |
$2.28/boe |
General and administrative (3) | |
$92 million ($1.65/boe) | |
No change | |
$43.4 million ($1.57/boe) |
Cash interest (3) | |
$190 million ($3.40/boe) | |
$200 million ($3.57/boe) | |
$107.2 million ($3.87/boe) |
Current income tax (4) | |
$40 million ($0.72/boe) | |
No change | |
$8.2 million ($0.29/boe) |
Leasing expenditures | |
$12 million | |
No change | |
$10.4 million |
Asset retirement
obligations | |
$30 million | |
No change | |
$13.6 million |
| (1) | As announced on December 6, 2023. |
| (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. |
| (4) | Current income tax expense per
boe is calculated as current income tax expense divided by barrels of oil equivalent production
volume for the applicable period. |
12 | Baytex Energy Corp. Second Quarter Report 2024 | |
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 operated and non-operated Eagle Ford assets in Texas.
Production
| |
Three Months Ended June 30 | |
| |
2024 | | |
2023 | |
| |
Canada | | |
U.S. | | |
Total | | |
Canada | | |
U.S. | | |
Total | |
Daily Production | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Liquids (bbl/d) | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Light oil and condensate | |
| 11,076 | | |
| 55,955 | | |
| 67,031 | | |
| 14,612 | | |
| 20,710 | | |
| 35,322 | |
Heavy oil | |
| 43,703 | | |
| — | | |
| 43,703 | | |
| 32,821 | | |
| — | | |
| 32,821 | |
Natural Gas Liquids
(NGL) | |
| 2,309 | | |
| 17,858 | | |
| 20,167 | | |
| 1,434 | | |
| 7,186 | | |
| 8,620 | |
Total liquids (bbl/d) | |
| 57,088 | | |
| 73,813 | | |
| 130,901 | | |
| 48,867 | | |
| 27,896 | | |
| 76,763 | |
Natural gas (mcf/d) | |
| 39,599 | | |
| 100,165 | | |
| 139,764 | | |
| 42,043 | | |
| 35,946 | | |
| 77,989 | |
Total production (boe/d) | |
| 63,688 | | |
| 90,506 | | |
| 154,194 | | |
| 55,874 | | |
| 33,887 | | |
| 89,761 | |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Production Mix | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Segment as a percent of total | |
| 41 | % | |
| 59 | % | |
| 100 | % | |
| 62 | % | |
| 38 | % | |
| 100 | % |
Light oil and condensate | |
| 17 | % | |
| 62 | % | |
| 44 | % | |
| 26 | % | |
| 61 | % | |
| 39 | % |
Heavy oil | |
| 69 | % | |
| — | % | |
| 28 | % | |
| 59 | % | |
| — | % | |
| 37 | % |
NGL | |
| 4 | % | |
| 20 | % | |
| 13 | % | |
| 3 | % | |
| 21 | % | |
| 10 | % |
Natural gas | |
| 10 | % | |
| 18 | % | |
| 15 | % | |
| 12 | % | |
| 18 | % | |
| 14 | % |
| |
Six Months Ended June 30 | |
| |
2024 | | |
2023 | |
| |
Canada | | |
U.S. | | |
Total | | |
Canada | | |
U.S. | | |
Total | |
Daily Production | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Liquids (bbl/d) | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Light oil and condensate | |
| 11,285 | | |
| 55,249 | | |
| 66,534 | | |
| 15,500 | | |
| 18,010 | | |
| 33,510 | |
Heavy oil | |
| 42,131 | | |
| — | | |
| 42,131 | | |
| 33,502 | | |
| — | | |
| 33,502 | |
Natural Gas Liquids
(NGL) | |
| 2,470 | | |
| 17,263 | | |
| 19,733 | | |
| 1,653 | | |
| 6,267 | | |
| 7,920 | |
Total liquids (bbl/d) | |
| 55,886 | | |
| 72,512 | | |
| 128,398 | | |
| 50,655 | | |
| 24,277 | | |
| 74,932 | |
Natural gas (mcf/d) | |
| 41,990 | | |
| 102,069 | | |
| 144,059 | | |
| 45,562 | | |
| 34,455 | | |
| 80,017 | |
Total production (boe/d) | |
| 62,884 | | |
| 89,523 | | |
| 152,407 | | |
| 58,249 | | |
| 30,020 | | |
| 88,269 | |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Production Mix | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Segment as a percent of total | |
| 41 | % | |
| 59 | % | |
| 100 | % | |
| 66 | % | |
| 34 | % | |
| 100 | % |
Light oil and condensate | |
| 18 | % | |
| 62 | % | |
| 44 | % | |
| 27 | % | |
| 60 | % | |
| 38 | % |
Heavy oil | |
| 67 | % | |
| — | % | |
| 28 | % | |
| 58 | % | |
| — | % | |
| 38 | % |
NGL | |
| 4 | % | |
| 19 | % | |
| 13 | % | |
| 3 | % | |
| 21 | % | |
| 9 | % |
Natural gas | |
| 11 | % | |
| 19 | % | |
| 15 | % | |
| 12 | % | |
| 19 | % | |
| 15 | % |
Production was 154,194 boe/d for Q2/2024 and
152,407 boe/d for YTD 2024 compared to 89,761 boe/d for Q2/2023 and 88,269 boe/d for YTD 2023. Production for Q2/2024 and YTD 2024 was
higher than the same periods of 2023 primarily due to production from the Eagle Ford properties acquired from Ranger along with our successful
development program in Canada.
| Baytex Energy Corp. Second Quarter Report 2024 | 13 |
In Canada, production was 63,688 boe/d for Q2/2024
and 62,884 boe/d for YTD 2024 compared to 55,874 boe/d for Q2/2023 and 58,249 boe/d for YTD 2023. Strong production results from our
successful light and heavy oil development programs resulted in a 7,814 boe/d increase in production for Q2/2024 and 4,635 boe/d for
YTD 2024 relative to the same periods of 2023. Higher production from our heavy oil development was partially offset by the disposition
of non-core light oil Viking assets in December 2023.
In the U.S., production was 90,506 boe/d for
Q2/2024 and 89,523 boe/d for YTD 2024 compared to 33,887 boe/d for Q2/2023 and 30,020 boe/d for YTD 2023. Production from the Merger
with Ranger was the primary factor that resulted in a 56,619 boe/d increase in production for Q2/2024 and 59,503 boe/d increase in production
for YTD 2024 relative to the same periods of 2023, respectively. Production from the acquired Eagle Ford assets is primarily operated
and is weighted towards light oil which resulted in a higher proportion of our total production being light oil in 2024.
Total production of 152,407 boe/d for YTD 2024
is consistent with expectations and our revised annual guidance of 152,000 - 154,000 boe/d.
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 pricing for crude oil improved
during Q2/2024 and YTD 2024 due to stable supply and demand and continued OPEC production curtailments along with ongoing geopolitical
tension. The WTI benchmark price averaged US$80.57/bbl for Q2/2024 and US$78.77/bbl for YTD 2024 compared to US$73.78/bbl for Q2/2023
and US$74.96/bbl for YTD 2023.
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$83.10/bbl during Q2/2024 and US$81.03/bbl during YTD 2024 which is
higher than US$75.01/bbl for Q2/2023 and US$76.22/bbl for YTD 2023. The MEH benchmark typically trades at a premium to WTI as a result
of access to global markets. The MEH benchmark premium to WTI was US$2.53/bbl and US$2.26/bbl for Q2/2024 and YTD 2024 compared to premiums
of US$1.23/bbl and US$1.26/bbl for Q2/2023 and YTD 2023, respectively. The MEH benchmark traded at a higher premium to WTI in both periods
of 2024 as a result of additional demand at the U.S. Gulf Coast.
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 and inventory levels in Western Canada. Canadian oil differentials narrowed during Q2/2024
after exports commenced from the TMX pipeline expansion in May. Delays in the TMX expansion resulted in increased pipeline apportionment
and reduced the available capacity to transport light and heavy crude oil out of the Western Canadian Sedimentary Basin earlier in 2024,
which caused differentials to be wider for YTD 2024.
We compare the price received for our light oil
production in Canada to the Edmonton par benchmark oil price. The Edmonton par price averaged $105.30/bbl during Q2/2024 and $98.73/bbl
during YTD 2024 compared to $95.13/bbl during Q2/2023 and $97.09/ bbl during YTD 2023. Edmonton par traded at a discount to WTI of US$3.62/bbl
for Q2/2024 and US$6.10/bbl for YTD 2024 compared to a discount of US$2.95/bbl for Q2/2023 and US$2.91/bbl for YTD 2023.
We compare the price received for our heavy oil
production in Canada to the WCS heavy oil benchmark. The WCS benchmark for Q2/2024 and YTD 2024 averaged $91.72/bbl and $84.68/bbl respectively,
compared to $78.85/bbl and $74.16/bbl for the same periods of 2023. The WCS heavy oil differential to WTI was US$13.55/bbl in Q2/2024
and US$16.44/bbl in YTD 2024 compared to US$15.07/bbl for Q2/2023 and US$19.92/bbl in YTD 2023 which was impacted by refinery turnarounds
and additional supply from Strategic Petroleum Reserve releases by the U.S. government.
Natural Gas
Natural gas prices in Canada and the U.S. were
lower in 2024 relative to 2023 after mild winter weather across most of North America resulted in weak natural gas demand and elevated
inventory levels.
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$1.89/mmbtu
for Q2/2024 and US$2.07/mmbtu for YTD 2024 compared to US$2.10/ mmbtu for Q2/2023 and US$2.76/mmbtu for YTD 2023.
In Canada, we receive natural gas pricing based
on the AECO benchmark which trades at a discount to NYMEX as a result of limited market access for Canadian natural gas production. The
AECO benchmark averaged $1.44/mcf during Q2/2024 and $1.74/ mcf during YTD 2024 which is lower than $2.35/mcf for Q2/2023 and $3.34/mcf
for YTD 2023.
14 | Baytex Energy Corp. Second Quarter Report 2024 | |
The following tables compare select benchmark prices and our average
realized selling prices for the three and six months ended June 30, 2024 and 2023.
| |
Three
Months Ended June 30 | | |
Six
Months Ended June 30 | |
| |
2024 | | |
2023 | | |
Change | | |
2024 | | |
2023 | | |
Change | |
Benchmark
Averages | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
WTI
oil (US$/bbl) (1) | |
| 80.57 | | |
| 73.78 | | |
| 6.79 | | |
| 78.77 | | |
| 74.96 | | |
| 3.81 | |
MEH
oil (US$/bbl) (2) | |
| 83.10 | | |
| 75.01 | | |
| 8.09 | | |
| 81.03 | | |
| 76.22 | | |
| 4.81 | |
MEH
oil differential to WTI (US$/bbl) | |
| 2.53 | | |
| 1.23 | | |
| 1.30 | | |
| 2.26 | | |
| 1.26 | | |
| 1.00 | |
Edmonton
par oil ($/bbl) (3) | |
| 105.30 | | |
| 95.13 | | |
| 10.17 | | |
| 98.73 | | |
| 97.09 | | |
| 1.64 | |
Edmonton
par oil differential to WTI (US$/bbl) | |
| (3.62 | ) | |
| (2.95 | ) | |
| (0.67 | ) | |
| (6.10 | ) | |
| (2.91 | ) | |
| (3.19 | ) |
WCS
heavy oil ($/bbl) (4) | |
| 91.72 | | |
| 78.85 | | |
| 12.87 | | |
| 84.68 | | |
| 74.16 | | |
| 10.52 | |
WCS
heavy oil differential to WTI (US$/bbl) | |
| (13.55 | ) | |
| (15.07 | ) | |
| 1.52 | | |
| (16.44 | ) | |
| (19.92 | ) | |
| 3.48 | |
AECO
natural gas ($/mcf) (5) | |
| 1.44 | | |
| 2.35 | | |
| (0.91 | ) | |
| 1.74 | | |
| 3.34 | | |
| (1.60 | ) |
NYMEX
natural gas (US$/mmbtu) (6) | |
| 1.89 | | |
| 2.10 | | |
| (0.21 | ) | |
| 2.07 | | |
| 2.76 | | |
| (0.69 | ) |
CAD/USD
average exchange rate | |
| 1.3684 | | |
| 1.3431 | | |
| 0.0253 | | |
| 1.3586 | | |
| 1.3475 | | |
| 0.0111 | |
| (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 | |
| |
2024 | | |
2023 | |
| |
Canada | | |
U.S. | | |
Total | | |
Canada | | |
U.S. | | |
Total | |
Average Realized
Sales Prices | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Light
oil and condensate ($/bbl) (1) | |
$ | 103.21 | | |
$ | 109.71 | | |
$ | 108.64 | | |
$ | 93.98 | | |
$ | 97.55 | | |
$ | 96.07 | |
Heavy
oil, net of blending and other expense ($/bbl) (2) | |
| 82.29 | | |
| — | | |
| 82.29 | | |
| 66.45 | | |
| — | | |
| 66.45 | |
NGL
($/bbl) (1) | |
| 24.48 | | |
| 27.30 | | |
| 26.98 | | |
| 28.92 | | |
| 25.07 | | |
| 25.71 | |
Natural
gas ($/mcf) (1) | |
| 1.23 | | |
| 2.37 | | |
| 2.04 | | |
| 2.64 | | |
| 2.52 | | |
| 2.58 | |
Total
sales, net of blending and other expense ($/boe) (2) | |
$ | 76.07 | | |
$ | 75.83 | | |
$ | 75.93 | | |
$ | 66.34 | | |
$ | 67.60 | | |
$ | 66.82 | |
| |
Six
Months Ended June 30 | |
| |
2024 | | |
2023 | |
| |
Canada | | |
U.S. | | |
Total | | |
Canada | | |
U.S. | | |
Total | |
Average Realized
Sales Prices | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Light
oil and condensate ($/bbl) (1) | |
$ | 97.02 | | |
$ | 105.87 | | |
$ | 104.37 | | |
$ | 96.74 | | |
$ | 99.96 | | |
$ | 98.47 | |
Heavy
oil, net of blending and other expense ($/bbl) (2) | |
| 74.07 | | |
| — | | |
| 74.07 | | |
| 58.69 | | |
| — | | |
| 58.69 | |
NGL
($/bbl) (1) | |
| 25.61 | | |
| 26.71 | | |
| 26.57 | | |
| 32.86 | | |
| 28.35 | | |
| 29.29 | |
Natural
gas ($/mcf) (1) | |
| 1.86 | | |
| 2.37 | | |
| 2.22 | | |
| 3.12 | | |
| 3.23 | | |
| 3.17 | |
Total
sales, net of blending and other expense ($/boe) (2) | |
$ | 69.29 | | |
$ | 73.19 | | |
$ | 71.58 | | |
$ | 62.91 | | |
$ | 69.60 | | |
$ | 65.18 | |
| (1) | Calculated
as light oil and condensate or NGL sales divided by barrels of oil equivalent production
volume for the applicable period, or natural gas sales divided by the production volume in
Mcf 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 2024 | 15 |
Average Realized Sales Prices
Our total sales, net of blending and other
expense per boe(1) was $75.93/boe for Q2/2024 and $71.58/boe for YTD 2024 compared to $66.82/boe for Q2/2023 and $65.18/boe
for YTD 2023. In Canada, our realized price of $76.07/boe for Q2/2024 was $9.73/boe higher than $66.34/boe for Q2/2023. Our realized
price in the U.S. was $75.83/boe in Q2/2024 which is $8.23/boe higher than $67.60/boe in Q2/2023. The increase in North American benchmark
prices was the primary factor that resulted in higher realized pricing for our operations in Canada and the U.S. in Q2/2024 and YTD 2024
relative to the same periods of 2023.
We compare our light oil realized price
in Canada to the Edmonton par benchmark price. Our realized light oil and condensate price(2) was $103.21/bbl for Q2/2024
and $97.02/bbl for YTD 2024 compared to $93.98/bbl for Q2/2023 and $96.74/bbl for YTD 2023. Our realized light oil and condensate price
represents a discount to the Edmonton par price of $2.09/bbl for Q2/2024 and $1.71/bbl for YTD 2024 compared to a discount of $1.15/bbl
in Q2/2023 and $0.35/bbl for YTD 2023. We realized a slightly wider discount to the Edmonton par price in both periods of 2024 relative
to 2023 due to temporary pricing adjustments related to new Duvernay production that did not meet certain specifications at the sales
point.
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 $109.71/bbl for Q2/2024
and $105.87/bbl for YTD 2024 compared to $97.55/bbl for Q2/2023 and $99.96/bbl for YTD 2023. Expressed in U.S. dollars, our realized
light oil and condensate price of US$80.17/bbl for Q2/2024 and US$77.93/bbl for YTD 2024 represent discounts to MEH of US$2.93/bbl and
US$3.10/bbl for Q2/2024 and YTD 2024 respectively, compared to discounts of US$2.38/bbl for Q2/2023 and US$2.04/bbl for YTD 2023 and
reflect the realized pricing on our operated Eagle Ford production acquired from Ranger.
Our realized heavy oil price, net of blending
and other expense(1) was $82.29/bbl in Q2/2024 and $74.07/bbl for YTD 2024 compared to $66.45/bbl in Q2/2023 and $58.69/bbl
for YTD 2023. Our realized heavy oil, net of blending and other expense for Q2/2024 and YTD 2024 was $15.84/bbl and $15.38/bbl higher
than Q2/2023 and YTD 2023 respectively, compared to a $12.87/bbl and $10.52/bbl increase in the WCS benchmark price over the same periods.
Our realized price increased more than the benchmark price as the cost of condensate purchased for blending was lower relative to the
price received for sales of the blended product based on the WCS benchmark in both periods of 2024 compared to 2023.
Our realized NGL price as a percentage
of WTI varies 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 $26.98/bbl in Q2/2024 or 24% of WTI (expressed in Canadian dollars) and $26.57/bbl in YTD 2024 or 25%
of WTI (expressed in Canadian dollars), compared to $25.71/bbl or 26% of WTI (expressed in Canadian dollars) in Q2/2023 and $29.29/bbl
or 29% of WTI (expressed in Canadian dollars) in YTD 2023. Our realized NGL price was slightly lower as a percentage of WTI in both periods
of 2024 primarily due to lower demand for NGL products relative to 2023.
We compare our realized natural gas price
in the U.S. to the NYMEX benchmark and to the AECO benchmark price in Canada. In the U.S., our realized natural gas price(2) was
US$1.73/mcf for Q2/2024 and US$1.74/mcf for YTD 2024 compared to US$1.88/mcf for Q2/2023 and US$2.40/mcf for YTD 2023 which is consistent
with the decrease in the NYMEX benchmark over the same period. In Canada our realized natural gas price was $1.23/mcf for Q2/2024 and
$1.86/mcf for YTD 2024 compared to $2.64/mcf in Q2/2023 and $3.12/mcf for YTD 2023. The decrease in our realized price for Q2/2024 relative
to Q2/2023 was more than the decrease in the AECO benchmark as a greater proportion of our sales were based on the daily AECO index which
was lower than the monthly AECO index. The decrease in our realized price for YTD 2024 relative to YTD 2023 was lower than the decrease
in the AECO benchmark as the daily AECO index was higher than the monthly AECO index during Q1/2024.
| (1) | Specified
financial measure that does not have any standardized meaning prescribed by IFRS and may
not be comparable with the calculation of similar measures presented by other entities. Refer
to the Specified Financial Measures section in this MD&A for further information. |
| (2) | Calculated
as light oil and condensate or NGL sales divided by barrels of oil equivalent production
volume for the applicable period, or natural gas sales divided by the production volume in
Mcf for the applicable period. |
16 | Baytex Energy Corp. Second Quarter Report 2024 | |
PETROLEUM AND NATURAL GAS SALES
| |
Three Months Ended June 30 | |
| |
2024 | | |
2023 | |
($ thousands) | |
Canada | | |
U.S. | | |
Total | | |
Canada | | |
U.S. | | |
Total | |
Oil sales | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Light oil and condensate | |
$ | 104,030 | | |
$ | 558,620 | | |
$ | 662,650 | | |
$ | 124,965 | | |
$ | 183,845 | | |
$ | 308,810 | |
Heavy oil | |
| 394,960 | | |
| — | | |
| 394,960 | | |
| 251,449 | | |
| — | | |
| 251,449 | |
NGL | |
| 5,144 | | |
| 44,366 | | |
| 49,510 | | |
| 3,772 | | |
| 16,391 | | |
| 20,163 | |
Total oil sales | |
| 504,134 | | |
| 602,986 | | |
| 1,107,120 | | |
| 380,186 | | |
| 200,236 | | |
| 580,422 | |
Natural gas sales | |
| 4,426 | | |
| 21,577 | | |
| 26,003 | | |
| 10,106 | | |
| 8,232 | | |
| 18,338 | |
Total petroleum and natural gas sales | |
| 508,560 | | |
| 624,563 | | |
| 1,133,123 | | |
| 390,292 | | |
| 208,468 | | |
| 598,760 | |
Blending and other expense | |
| (67,685 | ) | |
| — | | |
| (67,685 | ) | |
| (52,995 | ) | |
| — | | |
| (52,995 | ) |
Total sales, net of blending and other
expense (1) | |
$ | 440,875 | | |
$ | 624,563 | | |
$ | 1,065,438 | | |
$ | 337,297 | | |
$ | 208,468 | | |
$ | 545,765 | |
| |
Six Months Ended June 30 | |
| |
2024 | | |
2023 | |
($ thousands) | |
Canada | | |
U.S. | | |
Total | | |
Canada | | |
U.S. | | |
Total | |
Oil sales | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Light oil and condensate | |
$ | 199,251 | | |
$ | 1,064,514 | | |
$ | 1,263,765 | | |
$ | 271,420 | | |
$ | 325,855 | | |
$ | 597,275 | |
Heavy oil | |
| 699,884 | | |
| — | | |
| 699,884 | | |
| 468,534 | | |
| — | | |
| 468,534 | |
NGL | |
| 11,513 | | |
| 83,928 | | |
| 95,441 | | |
| 9,832 | | |
| 32,165 | | |
| 41,997 | |
Total oil sales | |
| 910,648 | | |
| 1,148,442 | | |
| 2,059,090 | | |
| 749,786 | | |
| 358,020 | | |
| 1,107,806 | |
Natural gas sales | |
| 14,225 | | |
| 44,000 | | |
| 58,225 | | |
| 26,128 | | |
| 20,162 | | |
| 46,290 | |
Total petroleum and natural gas sales | |
| 924,873 | | |
| 1,192,442 | | |
| 2,117,315 | | |
| 775,914 | | |
| 378,182 | | |
| 1,154,096 | |
Blending and other expense | |
| (131,893 | ) | |
| — | | |
| (131,893 | ) | |
| (112,676 | ) | |
| — | | |
| (112,676 | ) |
Total sales, net of blending and other
expense (1) | |
$ | 792,980 | | |
$ | 1,192,442 | | |
$ | 1,985,422 | | |
$ | 663,238 | | |
$ | 378,182 | | |
$ | 1,041,420 | |
| (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 $1.1 billion for Q2/2024 increased $519.7 million from $545.8 million reported for Q2/2023, while total sales, net of blending and
other expense of $2.0 billion for YTD 2024 increased from $1.0 billion reported for YTD 2023. The increase in total sales for both periods
of 2024 is primarily the result of the Merger with Ranger along with higher production from our successful development programs and higher
realized pricing relative to the same periods of 2023.
In Canada, total sales, net of blending and other
expense, of $440.9 million for Q2/2024 and $793.0 million for YTD 2024 increased from $337.3 million reported for Q2/2023 and $663.2
million for YTD 2023. The increase in our realized pricing for Q2/2024 relative to Q2/2023 resulted in a $56.4 million increase in total
sales, net of blending and other expense while higher production contributed to a $47.2 million increase in total sales, net of blending
and other expense, relative to Q2/2023. The increase in our realized pricing for YTD 2024 relative to YTD 2023 resulted in a $73.0 million
increase in total sales, net of blending and other expense while higher production contributed to a $56.7 million increase in total sales,
net of blending and other expense, relative to YTD 2023.
In the U.S., total petroleum and natural gas
sales of $624.6 million for Q2/2024 and $1.2 billion for YTD 2024 increased from $208.5 million reported for Q2/2023 and $378.2 million
for YTD 2023. The increase in production due to the Merger resulted in a $348.3 million increase in total sales in Q2/2024 relative to
Q2/2023 and higher realized pricing contributed to a $67.8 million increase in total sales relative to Q2/2023. Higher production in
YTD 2024 resulted in a $755.8 million increase in total sales relative to YTD 2023 and higher realized pricing contributed to a $58.5
million increase in total sales relative to YTD 2023.
| Baytex Energy Corp. Second Quarter Report 2024 | 17 |
ROYALTIES
Royalties are paid to various government entities
and to land and mineral rights owners. Royalties are calculated based on gross revenues or on operating netbacks less capital investment
for specific heavy oil projects and are generally expressed as a percentage of total sales, net of blending and other expense. The actual
royalty rates can vary for a number of reasons, including the commodity produced, royalty contract terms, commodity price level, royalty
incentives and the area or jurisdiction. The following table summarizes our royalties and royalty rates for the three and six months
ended June 30, 2024 and 2023.
| |
Three Months Ended June 30 | |
| |
2024 | | |
2023 | |
($ thousands except
for % and per boe) | |
Canada | | |
U.S. | | |
Total | | |
Canada | | |
U.S. | | |
Total | |
Royalties | |
$ | 72,894 | | |
$ | 167,546 | | |
$ | 240,440 | | |
$ | 47,309 | | |
$ | 60,611 | | |
$ | 107,920 | |
Average
royalty rate (1)(2) | |
| 16.5 | % | |
| 26.8 | % | |
| 22.6 | % | |
| 14.0 | % | |
| 29.1 | % | |
| 19.8 | % |
Royalties
per boe (3) | |
$ | 12.58 | | |
$ | 20.34 | | |
$ | 17.14 | | |
$ | 9.30 | | |
$ | 19.66 | | |
$ | 13.21 | |
| |
Six Months Ended June 30 | |
| |
2024 | | |
2023 | |
($
thousands except for % and per boe) | |
Canada | | |
U.S. | | |
Total | | |
Canada | | |
U.S. | | |
Total | |
Royalties | |
$ | 129,458 | | |
$ | 320,153 | | |
$ | 449,611 | | |
$ | 91,164 | | |
$ | 110,009 | | |
$ | 201,173 | |
Average
royalty rate (1)(2) | |
| 16.3 | % | |
| 26.8 | % | |
| 22.6 | % | |
| 13.7 | % | |
| 29.1 | % | |
| 19.3 | % |
Royalties
per boe (3) | |
$ | 11.31 | | |
$ | 19.65 | | |
$ | 16.21 | | |
$ | 8.65 | | |
$ | 20.25 | | |
$ | 12.59 | |
| (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 Q2/2024 were $240.4 million or
22.6% of total sales, net of blending and other expense, compared to $107.9 million or 19.8% for Q2/2023. Total royalties for YTD 2024
were $449.6 million or 22.6% of total sales, net of blending and other expense, compared to $201.2 million or 19.3% for YTD 2023. The
increase in total royalty expense and our average royalty rate in both periods of 2024 relative to 2023 is primarily a result of the
Merger with Ranger which resulted in higher total sales, net of blending and other expense, along with a higher proportion of our production
being from the Eagle Ford which has a higher royalty rate than our Canadian properties.
Our average royalty rate(1) in
Canada of 16.5% for Q2/2024 and 16.3% for YTD 2024 was higher than 14.0% for Q2/2023 and 13.7% for YTD 2023 as a result of heavy oil
production growth which has a higher royalty rate relative to our light oil properties, as well as increased realized and crown reference
prices on which crown royalties are calculated. In the U.S., royalties averaged 26.8% of total sales for both periods of 2024, which
is lower than 29.1% for the comparative periods of 2023 due to production from the acquired Ranger properties which have a lower royalty
rate relative to our legacy non-operated Eagle Ford properties.
Our average royalty rate of 22.6% for YTD 2024 is consistent with
our annual guidance of 23% for 2024.
| (1) | Specified financial measure that
does not have any standardized meaning prescribed by IFRS and may not be comparable with
the calculation of similar measures presented by other entities. Refer to the Specified Financial
Measures section in this MD&A for further information. |
18 | Baytex Energy Corp. Second Quarter Report 2024 | |
OPERATING EXPENSE
|
|
Three Months Ended June 30 | |
| |
2024 | | |
2023 | |
($ thousands except
for per boe) | |
Canada | | |
U.S. | | |
Total | | |
Canada | | |
U.S. | | |
Total | |
Operating expense | |
$ | 84,415 | | |
$ | 83,290 | | |
$ | 167,705 | | |
$ | 91,354 | | |
$ | 28,084 | | |
$ | 119,438 | |
Operating expense per boe (1) | |
$ | 14.57 | | |
$ | 10.11 | | |
$ | 11.95 | | |
$ | 17.97 | | |
$ | 9.11 | | |
$ | 14.62 | |
|
|
Six Months Ended June 30 | |
| |
2024 | | |
2023 | |
($ thousands except
for per boe) | |
Canada | | |
U.S. | | |
Total | | |
Canada | | |
U.S. | | |
Total | |
Operating expense | |
$ | 169,818 | | |
$ | 171,322 | | |
$ | 341,140 | | |
$ | 182,534 | | |
$ | 49,312 | | |
$ | 231,846 | |
Operating expense per boe (1) | |
$ | 14.84 | | |
$ | 10.51 | | |
$ | 12.30 | | |
$ | 17.31 | | |
$ | 9.08 | | |
$ | 14.51 | |
| (1) | Operating
expense per boe is calculated as operating expense divided by barrels of oil equivalent production
volume for the applicable period. |
Total operating expense was $167.7 million ($11.95/boe)
for Q2/2024 and $341.1 million ($12.30/boe) for YTD 2024 compared to $119.4 million ($14.62/boe) for Q2/2023 and $231.8 million ($14.51/boe)
for YTD 2023. Total operating expense for both periods of 2024 increased relative to 2023 due to higher production while lower per unit
operating costs reflect the lower per boe operating expense on the properties acquired from Ranger.
In Canada, total operating expense was $84.4
million ($14.57/boe) for Q2/2024 and $169.8 million ($14.84/boe) for YTD 2024 which was lower than $91.4 million ($17.97/boe) for Q2/2023
and $182.5 million ($17.31/boe) for YTD 2023. The decrease in total and per unit operating expense for both periods of 2024 relative
to the same periods of 2023 reflects production growth at Peavine along with the disposition of non-core Viking assets in Q4/2023.
In the U.S., operating expense was $83.3 million
($10.11/boe) for Q2/2024 and $171.3 million ($10.51/boe) for YTD 2024 compared to $28.1 million ($9.11/boe) for Q2/2023 and $49.3 million
($9.08/boe) for YTD 2023. Per boe operating expense in the U.S., expressed in U.S. dollars, was US$7.39/boe for Q2/2024 and US$7.74/boe
for YTD 2024 compared to US$6.78/boe for Q2/2023 and US$6.74/boe for YTD 2023. The increase in total and per unit operating expense for
both periods of 2024 relative to 2023 reflects the additional production from the properties acquired from Ranger along with higher workover
and maintenance costs on our non-operated acreage.
Operating expense of $12.30/boe for YTD 2024
is consistent with expectations and our annual guidance range of $11.25 - $12.00/ boe for 2024 reflects production growth over the remainder
of the year.
TRANSPORTATION EXPENSE
Transportation expense includes the costs incurred
to move production via truck or pipeline to the sales point. Transportation expense can vary from period to period as we seek to optimize
sales prices and transportation rates.
The following table compares our transportation expense for the three
and six months ended June 30, 2024 and 2023.
|
|
Three Months Ended June 30 | |
| |
2024 | | |
2023 | |
($ thousands except
for per boe) | |
Canada | | |
U.S. | | |
Total | | |
Canada | | |
U.S. | | |
Total | |
Transportation expense | |
$ | 19,569 | | |
$ | 13,745 | | |
$ | 33,314 | | |
$ | 13,240 | | |
$ | 1,334 | | |
$ | 14,574 | |
Transportation expense per boe (1) | |
$ | 3.38 | | |
$ | 1.67 | | |
$ | 2.37 | | |
$ | 2.60 | | |
$ | 0.43 | | |
$ | 1.78 | |
|
|
Six Months Ended June 30 | |
| |
2024 | | |
2023 | |
($ thousands except
for per boe) | |
Canada | | |
U.S. | | |
Total | | |
Canada | | |
U.S. | | |
Total | |
Transportation expense | |
$ | 37,779 | | |
$ | 25,370 | | |
$ | 63,149 | | |
$ | 30,245 | | |
$ | 1,334 | | |
$ | 31,579 | |
Transportation expense per boe (1) | |
$ | 3.30 | | |
$ | 1.56 | | |
$ | 2.28 | | |
$ | 2.87 | | |
$ | 0.25 | | |
$ | 1.98 | |
| (1) | Transportation
expense per boe is calculated as transportation expense divided by barrels of oil equivalent
production volume for the applicable period. |
| Baytex Energy Corp. Second Quarter Report 2024 | 19 |
Transportation expense was $33.3 million ($2.37/boe)
for Q2/2024 and $63.1 million ($2.28/boe) for YTD 2024 compared to $14.6 million ($1.78/boe) for Q2/2023 and $31.6 million ($1.98/boe)
for YTD 2023. In Canada, total transportation expense and per unit costs were higher in Q2/2024 and YTD 2024 as a result of additional
heavy oil production relative to the same periods of 2023. In the U.S., transportation expense and per unit costs were higher in both
periods of 2024 due to trucking and pipeline costs on our operated Eagle Ford operations acquired from Ranger.
Per unit transportation expense of $2.28/boe
for YTD 2024 is slightly below our annual guidance range of $2.35 - $2.55/boe for 2024.
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 $67.7 million
for Q2/2024 and $131.9 million for YTD 2024 compared to $53.0 million for Q2/2023 and $112.7 million for YTD 2023. Higher blending and
other expense is primarily a result of higher heavy oil production and pipeline shipments in Q2/2024 and YTD 2024 relative to same periods
in 2023.
FINANCIAL DERIVATIVES
As part of our normal operations, we are exposed
to movements in commodity prices, foreign exchange rates, interest rates and changes in our share price. In an effort to manage these
exposures, we utilize various financial derivative contracts which are intended to partially reduce the volatility in our free cash flow.
Contracts settled in the period result in realized gains or losses based on the market price compared to the contract price and the notional
volume outstanding. Changes in the fair value of unsettled contracts are reported as unrealized gains or losses in the period as the
forward markets fluctuate and as new contracts are executed. The following table summarizes the results of our financial derivative contracts
for the three and six months ended June 30, 2024 and 2023.
| |
Three
Months Ended June 30 | | |
Six
Months Ended June 30 | |
($
thousands) | |
2024 | | |
2023 | | |
Change | | |
2024 | | |
2023 | | |
Change | |
Realized
financial derivatives (loss) gain | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Crude
oil | |
$ | (4,847 | ) | |
$ | 16,363 | | |
$ | (21,210 | ) | |
$ | (3,900 | ) | |
$ | 21,778 | | |
$ | (25,678 | ) |
Natural
gas | |
| 2,590 | | |
| 2 | | |
| 2,588 | | |
| 7,131 | | |
| 2 | | |
| 7,129 | |
Total | |
$ | (2,257 | ) | |
$ | 16,365 | | |
$ | (18,622 | ) | |
$ | 3,231 | | |
$ | 21,780 | | |
$ | (18,549 | ) |
Unrealized
financial derivatives gain (loss) | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Crude
oil | |
$ | 13,476 | | |
$ | (17,124 | ) | |
$ | 30,600 | | |
$ | (17,989 | ) | |
$ | (7,914 | ) | |
$ | (10,075 | ) |
Natural
gas | |
| (2,686 | ) | |
| (2,279 | ) | |
| (407 | ) | |
| (3,571 | ) | |
| (2,279 | ) | |
| (1,292 | ) |
Total | |
$ | 10,790 | | |
$ | (19,403 | ) | |
$ | 30,193 | | |
$ | (21,560 | ) | |
$ | (10,193 | ) | |
$ | (11,367 | ) |
Total
financial derivatives gain (loss) | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Crude
oil | |
$ | 8,629 | | |
$ | (761 | ) | |
$ | 9,390 | | |
$ | (21,889 | ) | |
$ | 13,864 | | |
$ | (35,753 | ) |
Natural
gas | |
| (96 | ) | |
| (2,277 | ) | |
| 2,181 | | |
| 3,560 | | |
| (2,277 | ) | |
| 5,837 | |
Total | |
$ | 8,533 | | |
$ | (3,038 | ) | |
$ | 11,571 | | |
$ | (18,329 | ) | |
$ | 11,587 | | |
$ | (29,916 | ) |
We recorded a total financial derivatives gain
of $8.5 million for Q2/2024 and a loss of $18.3 million for YTD 2024 compared to a loss of $3.0 million for Q2/2023 and a gain of $11.6
million for YTD 2023. The realized financial derivatives gain of $3.2 million for YTD 2024 resulted from gains of $7.1 million on natural
gas contracts, offset by losses of $3.9 million on crude oil contracts. The unrealized financial derivatives loss of $21.6 million for
YTD 2024 resulted from a $3.6 million loss on natural gas contracts and a $18.0 million loss on crude oil contracts. The YTD loss is
primarily due to changes in forecasted crude oil pricing used to revalue the volumes outstanding on our crude oil contracts in place
at June 30, 2024 relative to December 31, 2023. The fair value of our financial derivative contracts resulted in a net asset
of $1.7 million at June 30, 2024 compared to a net asset of $23.3 million at December 31, 2023.
20 | Baytex Energy Corp. Second Quarter Report 2024 | |
As at July 25, 2024, we had the following commodity financial
derivative contracts for the period subsequent to June 30, 2024.
|
|
Remaining
Period |
|
Volume |
|
Price/Unit
(1) |
|
Index |
Oil |
|
|
|
|
|
|
|
|
Basis
differential |
|
July 2024
to Dec 2024 |
|
15,000
bbl/d |
|
Baytex pays: WCS differential at Hardisty Baytex receives:
WCS differential at Houston less US$8.31/bbl |
|
WCS |
Basis differential |
|
July 2024 to Dec 2024 |
|
6,000 bbl/d |
|
WTI less US$13.58/bbl |
|
WCS |
Basis differential |
|
July 2024 to Dec 2024 |
|
8,250 bbl/d |
|
WTI less US$2.78/bbl |
|
MSW |
Basis differential |
|
Jan 2025 to Dec 2025 |
|
2,000 bbl/d |
|
WTI less US$2.75/bbl |
|
MSW |
Collar |
|
July 2024 to Dec 2024 |
|
10,000 bbl/d |
|
US$60.00/US$100.00 |
|
WTI |
Collar |
|
July 2024 to Sep 2024 |
|
10,000 bbl/d |
|
US$60.00/US$100.00 |
|
WTI |
Collar |
|
July 2024 to Dec 2024 |
|
2,500 bbl/d |
|
US$60.00/US$94.15 |
|
WTI |
Collar |
|
July 2024 to Dec 2024 |
|
1,500 bbl/d |
|
US$60.00/US$90.35 |
|
WTI |
Collar |
|
July 2024 to Dec 2024 |
|
1,000 bbl/d |
|
US$60.00/US$90.00 |
|
WTI |
Collar |
|
July 2024 to Dec 2024 |
|
2,000 bbl/d |
|
US$60.00/US$85.00 |
|
WTI |
Collar |
|
July 2024 to Dec 2024 |
|
2,000 bbl/d |
|
US$60.00/US$84.60 |
|
WTI |
Collar |
|
July 2024 to Dec 2024 |
|
5,000 bbl/d |
|
US$60.00/US$84.15 |
|
WTI |
Collar |
|
Oct 2024 to Dec 2024 |
|
2,500 bbl/d |
|
US$60.00/US$100.00 |
|
WTI |
Collar |
|
Oct 2024 to Dec 2024 |
|
3,500 bbl/d |
|
US$60.00/US$87.10 |
|
WTI |
Collar |
|
Oct 2024 to Dec 2024 |
|
3,500 bbl/d |
|
US$60.00/US$85.75 |
|
WTI |
Collar |
|
Jan 2025 to Mar 2025 |
|
5,000 bbl/d |
|
US$60.00/US$88.70 |
|
WTI |
Collar |
|
Jan 2025 to Mar 2025 |
|
2,500 bbl/d |
|
US$60.00/US$90.20 |
|
WTI |
Collar |
|
Jan 2025 to Mar 2025 |
|
2,500 bbl/d |
|
US$60.00/US$90.05 |
|
WTI |
Collar |
|
Jan 2025 to Mar 2025 |
|
7,500 bbl/d |
|
US$60.00/US$90.00 |
|
WTI |
Collar |
|
Jan 2025 to Jun 2025 |
|
2,500 bbl/d |
|
US$60.00/US$94.25 |
|
WTI |
Collar |
|
Jan 2025 to Jun 2025 |
|
2,500 bbl/d |
|
US$60.00/US$93.90 |
|
WTI |
Collar |
|
Jan 2025 to Jun 2025 |
|
5,000 bbl/d |
|
US$60.00/US$91.95 |
|
WTI |
Collar |
|
Jan 2025 to Jun 2025 |
|
2,500 bbl/d |
|
US$60.00/US$90.00 |
|
WTI |
Collar |
|
Jan 2025 to Jun 2025 |
|
3,000 bbl/d |
|
US$60.00/US$89.55 |
|
WTI |
Collar |
|
Apr 2025 to Jun 2025 |
|
2,000 bbl/d |
|
US$60.00/US$88.17 |
|
WTI |
Collar (2) |
|
Apr 2025 to Jun 2025 |
|
5,000 bbl/d |
|
US$60.00/US$90.50 |
|
WTI |
Collar (2) |
|
Apr 2025 to Jun 2025 |
|
3,000 bbl/d |
|
US$60.00/US$90.60 |
|
WTI |
|
|
|
|
|
|
|
|
|
Natural Gas |
|
|
|
|
|
|
|
|
Collar |
|
July 2024 to Dec 2024 |
|
5,000 mmbtu/d |
|
US$3.00/US$4.185 |
|
NYMEX |
Collar |
|
July 2024 to Dec 2024 |
|
8,500 mmbtu/d |
|
US$3.00/US$4.15 |
|
NYMEX |
Collar |
|
July 2024 to Dec 2024 |
|
5,000 mmbtu/d |
|
US$3.00/US$4.10 |
|
NYMEX |
Collar |
|
July 2024 to Dec 2024 |
|
2,500 mmbtu/d |
|
US$3.00/US$4.09 |
|
NYMEX |
Collar |
|
July 2024 to Dec 2024 |
|
2,500 mmbtu/d |
|
US$3.00/US$4.06 |
|
NYMEX |
Collar |
|
Jan 2025 to Dec 2025 |
|
7,000 mmbtu/d |
|
US$3.00/US$4.01 |
|
NYMEX |
Collar |
|
Jan 2025 to Dec 2025 |
|
5,000 mmbtu/d |
|
US$3.25/US$4.03 |
|
NYMEX |
Collar |
|
Jan 2025 to Dec 2025 |
|
5,000 mmbtu/d |
|
US$3.25/US$4.08 |
|
NYMEX |
Collar |
|
Jan 2025 to Dec 2025 |
|
3,000 mmbtu/d |
|
US$3.25/US$4.135 |
|
NYMEX |
Collar |
|
Jan 2025 to Dec 2025 |
|
5,500 mmbtu/d |
|
US$3.25/US$4.14 |
|
NYMEX |
Collar |
|
Jan 2025 to Dec 2025 |
|
7,000 mmbtu/d |
|
US$3.00/US$4.32 |
|
NYMEX |
Collar |
|
Jan 2025 to Dec 2025 |
|
3,000 mmbtu/d |
|
US$3.00/US$4.85 |
|
NYMEX |
Collar |
|
Jan 2025 to Dec 2025 |
|
8,000 mmbtu/d |
|
US$3.00/US$4.855 |
|
NYMEX |
Collar |
|
Jan 2026 to Dec 2026 |
|
11,000 mmbtu/d |
|
US$3.25/US$5.02 |
|
NYMEX |
| (1) | Based
on the weighted average price per unit for the period. |
| (2) | Contract
entered subsequent to June 30, 2024. |
| Baytex Energy Corp. Second Quarter Report 2024 | 21 |
OPERATING NETBACK
The following table summarizes our operating netback
on a per boe basis for our Canadian and U.S. operations for the three and six months ended June 30, 2024 and 2023.
| |
Three Months Ended June 30 | |
| |
2024 | | |
2023 | |
($ per boe except for volume) | |
Canada | | |
U.S. | | |
Total | | |
Canada | | |
U.S. | | |
Total | |
Total production (boe/d) | |
| 63,688 | | |
| 90,506 | | |
| 154,194 | | |
| 55,874 | | |
| 33,887 | | |
| 89,761 | |
Operating netback: | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Total sales, net of blending and other expense (1) | |
$ | 76.07 | | |
$ | 75.83 | | |
$ | 75.93 | | |
$ | 66.34 | | |
$ | 67.60 | | |
$ | 66.82 | |
Less: | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Royalties (2) | |
| (12.58 | ) | |
| (20.34 | ) | |
| (17.14 | ) | |
| (9.30 | ) | |
| (19.66 | ) | |
| (13.21 | ) |
Operating expense (2) | |
| (14.57 | ) | |
| (10.11 | ) | |
| (11.95 | ) | |
| (17.97 | ) | |
| (9.11 | ) | |
| (14.62 | ) |
Transportation
expense (2) | |
| (3.38 | ) | |
| (1.67 | ) | |
| (2.37 | ) | |
| (2.60 | ) | |
| (0.43 | ) | |
| (1.78 | ) |
Operating netback (1) | |
$ | 45.54 | | |
$ | 43.71 | | |
$ | 44.47 | | |
$ | 36.47 | | |
$ | 38.40 | | |
$ | 37.21 | |
Realized financial derivatives gain (loss)
(3) | |
| — | | |
| — | | |
| (0.16 | ) | |
| — | | |
| — | | |
| 2.00 | |
Operating netback after financial derivatives
(1) | |
$ | 45.54 | | |
$ | 43.71 | | |
$ | 44.31 | | |
$ | 36.47 | | |
$ | 38.40 | | |
$ | 39.21 | |
| |
Six Months Ended June 30 | |
| |
2024 | | |
2023 | |
($ per boe except for volume) | |
Canada | | |
U.S. | | |
Total | | |
Canada | | |
U.S. | | |
Total | |
Total production (boe/d) | |
| 62,884 | | |
| 89,523 | | |
| 152,407 | | |
| 58,249 | | |
| 30,020 | | |
| 88,269 | |
Operating netback: | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Total sales, net of blending and other expense (1) | |
$ | 69.29 | | |
$ | 73.19 | | |
$ | 71.58 | | |
$ | 62.91 | | |
$ | 69.60 | | |
$ | 65.18 | |
Less: | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Royalties (2) | |
| (11.31 | ) | |
| (19.65 | ) | |
| (16.21 | ) | |
| (8.65 | ) | |
| (20.25 | ) | |
| (12.59 | ) |
Operating expense (2) | |
| (14.84 | ) | |
| (10.51 | ) | |
| (12.30 | ) | |
| (17.31 | ) | |
| (9.08 | ) | |
| (14.51 | ) |
Transportation
expense (2) | |
| (3.30 | ) | |
| (1.56 | ) | |
| (2.28 | ) | |
| (2.87 | ) | |
| (0.25 | ) | |
| (1.98 | ) |
Operating netback (1) | |
$ | 39.84 | | |
$ | 41.47 | | |
$ | 40.79 | | |
$ | 34.08 | | |
$ | 40.02 | | |
$ | 36.10 | |
Realized financial derivatives gain (3) | |
| — | | |
| — | | |
| 0.12 | | |
| — | | |
| — | | |
| 1.36 | |
Operating netback after financial derivatives
(1) | |
$ | 39.84 | | |
$ | 41.47 | | |
$ | 40.91 | | |
$ | 34.08 | | |
$ | 40.02 | | |
$ | 37.46 | |
| (1) | Specified financial measure that does not have any standardized meaning prescribed by IFRS and may
not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section
in this MD&A for further information. |
| (2) | Refer to Royalties, Operating Expense and Transportation Expense sections in this MD&A for a description
of the composition these measures. |
| (3) | Calculated as realized financial derivatives gain or loss divided by barrels of oil equivalent production
volume for the applicable period. |
Our operating netback of $44.47/boe for Q2/2024
and $40.79/boe for YTD 2024 was higher than $37.21/boe for Q2/2023 and $36.10/boe for YTD 2023 due to the increase in our realized price
which resulted in higher per unit sales net of royalties. In 2024, a higher proportion of our production was from our U.S. properties
which have lower operating and transportation expense resulting in total operating and transportation expense of $14.32/boe for Q2/2024
and $14.58/boe for YTD 2024, which was lower than $16.40/boe for Q2/2023 and $16.49/boe for YTD 2023. Our operating netback net of realized
gains and losses on financial derivatives was $44.31/boe for Q2/2024 and $40.91/boe for YTD 2024 compared to $39.21/boe for Q2/2023 and
$37.46/boe for YTD 2023.
GENERAL AND ADMINISTRATIVE EXPENSE
General and administrative ("G&A")
expense includes head office and corporate costs such as salaries and employee benefits, public company costs and administrative recoveries
earned for operating exploration and development activities on behalf of our working interest partners. G&A expense fluctuates with
head office staffing levels and the level of operated exploration and development activity during the period.
22 | Baytex Energy Corp. Second Quarter Report 2024 | |
The following table summarizes our G&A expense for the three and
six months ended June 30, 2024 and 2023.
| |
Three
Months Ended June 30 | | |
Six
Months Ended June 30 | |
($ thousands except for per boe) | |
2024 | | |
2023 | | |
Change | | |
2024 | | |
2023 | | |
Change | |
Gross general and administrative expense | |
$ | 27,064 | | |
$ | 16,476 | | |
$ | 10,588 | | |
$ | 55,827 | | |
$ | 30,893 | | |
$ | 24,934 | |
Overhead recoveries | |
| (6,058 | ) | |
| (1,236 | ) | |
| (4,822 | ) | |
| (12,409 | ) | |
| (3,919 | ) | |
| (8,490 | ) |
General and administrative expense | |
$ | 21,006 | | |
$ | 15,240 | | |
$ | 5,766 | | |
$ | 43,418 | | |
$ | 26,974 | | |
$ | 16,444 | |
General and administrative expense per
boe (1) | |
$ | 1.50 | | |
$ | 1.87 | | |
$ | (0.37 | ) | |
$ | 1.57 | | |
$ | 1.69 | | |
$ | (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 $21.0 million ($1.50/boe)
for Q2/2024 and $43.4 million ($1.57/boe) for YTD 2024 compared to $15.2 million ($1.87/boe) for Q2/2023 and $27.0 million ($1.69/boe)
for YTD 2023. G&A expense for Q2/2024 and YTD 2024 was higher than both periods of 2023 due to staffing costs associated with the
personnel retained following the Merger with Ranger. G&A expense of $1.57/boe for YTD 2024 is consistent with our 2024 annual guidance
of $1.65/boe.
FINANCING AND INTEREST EXPENSE
Financing and interest expense includes interest
on our credit facilities, long-term notes and lease obligations as well as non-cash financing costs which include the accretion on our
debt issue costs and asset retirement obligations. Financing and interest expense varies depending on debt levels outstanding during the
period, the applicable borrowing rates, CAD/USD foreign exchange rates, along with the carrying amount of asset retirement obligations
and the discount rates used to present value these obligations.
The following table summarizes our financing and interest expense for
the three and six months ended June 30, 2024 and 2023.
| |
Three
Months Ended June 30 | | |
Six
Months Ended June 30 | |
($ thousands except for per boe) | |
2024 | | |
2023 | | |
Change | | |
2024 | | |
2023 | | |
Change | |
Interest on credit facilities | |
$ | 15,639 | | |
$ | 7,535 | | |
$ | 8,104 | | |
$ | 33,928 | | |
$ | 13,751 | | |
$ | 20,177 | |
Interest on long-term notes | |
| 37,656 | | |
| 20,565 | | |
| 17,091 | | |
| 72,334 | | |
| 32,659 | | |
| 39,675 | |
Interest on lease obligations | |
| 651 | | |
| 155 | | |
| 496 | | |
| 964 | | |
| 220 | | |
| 744 | |
Cash interest | |
$ | 53,946 | | |
$ | 28,255 | | |
$ | 25,691 | | |
$ | 107,226 | | |
$ | 46,630 | | |
$ | 60,596 | |
Accretion of debt issue costs | |
| 7,862 | | |
| 1,847 | | |
| 6,015 | | |
| 10,922 | | |
| 2,371 | | |
| 8,551 | |
Accretion of asset retirement obligations | |
| 5,459 | | |
| 4,395 | | |
| 1,064 | | |
| 10,386 | | |
| 9,221 | | |
| 1,165 | |
Early redemption expense | |
| 24,350 | | |
| — | | |
| 24,350 | | |
| 24,350 | | |
| — | | |
| 24,350 | |
Financing and interest expense | |
$ | 91,617 | | |
$ | 34,497 | | |
$ | 57,120 | | |
$ | 152,884 | | |
$ | 58,222 | | |
$ | 94,662 | |
Cash interest per boe (1) | |
$ | 3.84 | | |
$ | 3.46 | | |
$ | 0.38 | | |
$ | 3.87 | | |
$ | 2.92 | | |
$ | 0.95 | |
Financing and interest expense per boe
(1) | |
$ | 6.53 | | |
$ | 4.22 | | |
$ | 2.31 | | |
$ | 5.51 | | |
$ | 3.64 | | |
$ | 1.87 | |
| (1) | Calculated as cash interest
or financing and interest expense divided by barrels of oil equivalent production volume for the applicable period. |
Financing and interest expense was $91.6 million
($6.53/boe) for Q2/2024 and $152.9 million ($5.51/boe) for YTD 2024 compared to $34.5 million ($4.22/boe) for Q2/2023 and $58.2 million
($3.64/boe) for YTD 2023. Higher interest costs in 2024 compared to 2023 are primarily the result of the additional debt outstanding after
the Merger with Ranger and also includes costs incurred related to the early redemption of the 8.75% notes on April 1, 2024.
Cash interest of $53.9 million ($3.84/boe) for
Q2/2024 and $107.2 million ($3.87/boe) for YTD 2024 was higher than $28.3 million ($3.46/boe) for Q2/2023 and $46.6 million ($2.92/boe)
for YTD 2023, primarily due to higher debt balances outstanding after the Merger, which included the issuance of US$800.0 million aggregate
principal amount of long-term notes. Interest on our credit facilities increased in Q2/2024 relative to Q2/2023 due to higher applicable
borrowing rates along with additional principal amounts outstanding following the Merger. The weighted average interest rate applicable
on our credit facilities was 7.9% for Q2/2024 and 8.0% for YTD 2024 compared to 6.8% for Q2/2023 and 6.5% for YTD 2023.
Accretion of asset retirement obligations of $5.5
million for Q2/2024 and $10.4 million for YTD 2024 was consistent with $4.4 million for Q2/2023 and $9.2 million for YTD 2023. Accretion
of debt issue costs was higher for 2024 compared to 2023 due to the increase in debt issue costs associated with the credit facilities
and new long-term notes issued to fund the Merger with Ranger. We also recorded $24.4 million of early redemption expense related to the
8.75% senior notes which were redeemed in Q2/2024 using the proceeds from the issuance of US$575 million aggregate principal amount of
senior unsecured notes due 2032.
| Baytex Energy Corp. Second Quarter Report 2024 | 23 |
We have revised our cash interest expense annual
guidance for 2024 to $200 million ($3.57/boe), up from $190 million ($3.40/boe) previously.
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 $0.6 million for Q2/2024 and $0.7 million for YTD 2024 compared to $0.4 million for Q2/2023 and $0.5 million for YTD 2023.
DEPLETION AND DEPRECIATION
Depletion and depreciation expense varies with
the carrying amount of the Company's oil and gas properties, the amount of proved and probable reserves volumes and the rate of production
for the period. The following table summarizes depletion and depreciation expense for the three and six months ended June 30, 2024
and 2023.
| |
Three Months Ended June 30 | | |
Six Months Ended June 30 | |
($ thousands except for per boe) | |
2024 | | |
2023 | | |
Change | | |
2024 | | |
2023 | | |
Change | |
Depletion | |
$ | 349,718 | | |
$ | 174,473 | | |
$ | 175,245 | | |
$ | 691,153 | | |
$ | 338,908 | | |
$ | 352,245 | |
Depreciation | |
| 3,383 | | |
| 1,671 | | |
| 1,712 | | |
| 6,085 | | |
| 3,235 | | |
| 2,850 | |
Depletion and depreciation | |
$ | 353,101 | | |
$ | 176,144 | | |
$ | 176,957 | | |
$ | 697,238 | | |
$ | 342,143 | | |
$ | 355,095 | |
Depletion and depreciation per boe (1) | |
$ | 25.16 | | |
$ | 21.56 | | |
$ | 3.60 | | |
$ | 25.14 | | |
$ | 21.42 | | |
$ | 3.72 | |
| (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 $353.1
million ($25.16/boe) for Q2/2024 and $697.2 million ($25.14/boe) for YTD 2024 compared to $176.1 million ($21.56/boe) for Q2/2023 and
$342.1 million ($21.42/boe) for YTD 2023. Total depletion and depreciation expense and depletion and depreciation per boe were higher
in Q2/2024 and YTD 2024 relative to Q2/2023 and YTD 2023 due to depletion on the assets acquired from Ranger which have a higher depletion
rate than our other properties. The effect of the Merger was partially offset by an impairment loss of $833.7 million that was recorded
at December 31, 2023.
IMPAIRMENT
We did not identify indicators of impairment or impairment reversal
for any of our cash generating units ("CGUs") at June 30, 2024.
2023 Impairment
At December 31, 2023, we identified indicators
of impairment for oil and gas properties in our legacy non-operated Eagle Ford CGU due to changes in our reserves and in our Viking CGU
due to changes in our reserves and a loss recorded on a disposition of an asset. We recorded an impairment loss of $833.7 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. 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 share-based compensation liability. SBC expense varies with the quantity of unvested share awards outstanding
and changes in the market price of our common shares.
We recorded SBC expense of $5.6 million for Q2/2024
and $15.1 million for YTD 2024 which is lower than $16.9 million for Q2/2023 and $26.7 million for YTD 2023. SBC expense for Q2/2024 and
YTD 2024 decreased relative to the same periods of 2023 as Q2/2023 and YTD 2023 includes $16.2 million of non-cash expense related to
awards assumed and settled in Baytex common shares in conjunction with the Merger with Ranger. This decrease in SBC expense was partially
offset by an increase in the Company's share price during YTD 2024. Regular expensing of compensation awards is considered a cash expense
as we intend to settle currently outstanding and future awards in cash while Baytex is repurchasing shares as part of its shareholder
return program.
24 | Baytex Energy Corp. Second Quarter Report 2024 | |
FOREIGN EXCHANGE
Unrealized foreign exchange gains and losses are
primarily a result of changes in the reported amount of our U.S. dollar denominated long-term notes and credit facilities in our Canadian
functional currency entities. The long-term notes and credit facilities are translated to Canadian dollars on the balance sheet date using
the closing CAD/USD exchange rate resulting in unrealized gains and losses. Realized foreign exchange gains and losses are due to day-to-day
U.S. dollar denominated transactions occurring in our Canadian functional currency entities.
| |
Three
Months Ended June 30 | | |
Six
Months Ended June 30 | |
($ thousands except for exchange rates) | |
2024 | | |
2023 | | |
Change | | |
2024 | | |
2023 | | |
Change | |
Unrealized foreign exchange loss (gain) | |
$ | 19,189 | | |
$ | (12,880 | ) | |
$ | 32,069 | | |
$ | 57,907 | | |
$ | (13,093 | ) | |
$ | 71,000 | |
Realized foreign exchange loss | |
| 866 | | |
| 941 | | |
| (75 | ) | |
| 2,085 | | |
| 1,091 | | |
| 994 | |
Foreign exchange loss (gain) | |
$ | 20,055 | | |
$ | (11,939 | ) | |
$ | 31,994 | | |
$ | 59,992 | | |
$ | (12,002 | ) | |
$ | 71,994 | |
CAD/USD exchange rates: | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
At beginning of period | |
| 1.3533 | | |
| 1.3528 | | |
| | | |
| 1.3205 | | |
| 1.3534 | | |
| | |
At end of period | |
| 1.3687 | | |
| 1.3238 | | |
| | | |
| 1.3687 | | |
| 1.3238 | | |
| | |
We recorded a foreign exchange loss of $20.1 million
for Q2/2024 and $60.0 million for YTD 2024 compared to a gain of $11.9 million for Q2/2023 and $12.0 million for YTD 2023.
The unrealized foreign exchange loss of $19.2
million for Q2/2024 and $57.9 million for YTD 2024 is due to an increase in the reported amount of our long-term notes and credit facilities
as a result of a weaker Canadian dollar relative to the U.S. dollar at June 30, 2024 compared to March 31, 2024 and December 31,
2023. The unrealized foreign exchange gain of $12.9 million for Q2/2023 and $13.1 million for YTD 2023 is due to a decrease in the reported
amount of our long-term notes 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.
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 functional currency entities.
We recorded a realized foreign exchange loss of $0.9 million for Q2/2024 and $2.1 million for YTD 2024 compared to a loss of $0.9 million
for Q2/2023 and $1.1 million for YTD 2023.
INCOME TAXES
| |
Three
Months Ended June 30 | | |
Six
Months Ended June 30 | |
($ thousands) | |
2024 | | |
2023 | | |
Change | | |
2024 | | |
2023 | | |
Change | |
Current income tax expense | |
$ | 6,475 | | |
$ | 1,350 | | |
$ | 5,125 | | |
$ | 8,155 | | |
$ | 2,470 | | |
$ | 5,685 | |
Deferred income tax expense (recovery) | |
| 22,810 | | |
| (178,360 | ) | |
| 201,170 | | |
| 38,611 | | |
| (162,837 | ) | |
| 201,448 | |
Total income tax expense (recovery) | |
$ | 29,285 | | |
$ | (177,010 | ) | |
$ | 206,295 | | |
$ | 46,766 | | |
$ | (160,367 | ) | |
$ | 207,133 | |
Current income tax expense per boe | |
$ | 0.46 | | |
$ | 0.17 | | |
$ | 0.29 | | |
$ | 0.29 | | |
$ | 0.15 | | |
$ | 0.14 | |
Current income tax expense was $6.5 million for
Q2/2024 and $8.2 million for YTD 2024 compared to $1.4 million for Q2/2023 and $2.5 million for YTD 2023. The current tax expense recorded
in Q2/2024 and YTD 2024 primarily relates to repatriation and related taxes, which have increased from the same periods of 2023 as a result
of the Merger. We expect current income tax expense of $40 million ($0.72/boe) for 2024.
We recorded deferred tax expense of $22.8 million
for Q2/2024 and $38.6 million for YTD 2024 compared to a recovery of $178.4 million for Q2/2023 and $162.8 million for YTD 2023. The deferred
tax expense recorded in Q2/2024 and YTD 2024 reflects income generated on our U.S. operations for the period as the tax pools associated
with our Canadian operations are subject to a valuation allowance. The deferred tax recovery recorded 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.
In June 2016, certain indirect subsidiary
entities received reassessments from the Canada Revenue Agency ("CRA") that deny non-capital loss deductions relevant to the
calculation of income taxes for the years 2011 through 2015. Following objections and submissions, in November 2023 the CRA issued
notices of confirmation regarding their prior reassessments. In February 2024, Baytex filed notices of appeal with the Tax Court
of Canada and we estimate it could take between two and three years to receive a judgment. The reassessments do not require us to pay
any amounts in order to participate in the appeals process. Should we be unsuccessful at the Tax Court of Canada, additional appeals are
available; a process that we estimate could take another two years and potentially longer.
| Baytex Energy Corp. Second Quarter Report 2024 | 25 |
We remain confident that the tax filings of the
affected entities are correct and will defend our tax filing positions. During Q4/2023, we purchased $272.5 million of insurance coverage
for a premium of $50.3 million which will help manage the litigation risk associated with this matter. The most recent reassessments issued
by the CRA assert taxes owing by the trusts of $244.8 million, late payment interest of $208.6 million as at the date of reassessments
and a late filing penalty in respect of the 2011 tax year of $4.1 million.
By way of background, we acquired several privately
held commercial trusts in 2010 with accumulated non-capital losses of $591.0 million (the "Losses"). The Losses were subsequently
deducted in computing the taxable income of those trusts. The reassessments, as confirmed in November 2023, disallow the deduction
of the Losses for two reasons. First, the reassessments allege that the trusts were resettled and the resulting successor trusts were
not able to access the losses of the predecessor trusts. Second, the reassessments allege that the general anti-avoidance rule of
the Income Tax Act (Canada) operates to deny the deduction of the losses. If, after exhausting available appeals, the deduction of Losses
continues to be disallowed, either the trusts or their corporate beneficiary will owe cash taxes, late payment interest and potential
penalties. The amount of cash taxes owing, late payment interest and potential penalties are dependent upon the taxpayer(s) ultimately
liable (the trusts or their corporate beneficiary) and the amount of unused tax shelter available to the taxpayer(s) to offset the
reassessed income, including tax shelter from subsequent years that may be carried back and applied to prior years.
26 | Baytex Energy Corp. Second Quarter Report 2024 | |
NET INCOME AND ADJUSTED FUNDS FLOW
The components of adjusted funds flow and net
income for the three and six months ended June 30, 2024 and 2023 are set forth in the following table.
| |
Three
Months Ended June 30 | | |
Six
Months Ended June 30 | |
($
thousands) | |
2024 | | |
2023 | | |
Change | | |
2024 | | |
2023 | | |
Change | |
Petroleum
and natural gas sales | |
$ | 1,133,123 | | |
$ | 598,760 | | |
$ | 534,363 | | |
$ | 2,117,315 | | |
$ | 1,154,096 | | |
$ | 963,219 | |
Royalties | |
| (240,440 | ) | |
| (107,920 | ) | |
| (132,520 | ) | |
| (449,611 | ) | |
| (201,173 | ) | |
| (248,438 | ) |
Revenue,
net of royalties | |
| 892,683 | | |
| 490,840 | | |
| 401,843 | | |
| 1,667,704 | | |
| 952,923 | | |
| 714,781 | |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Expenses | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Operating | |
| (167,705 | ) | |
| (119,438 | ) | |
| (48,267 | ) | |
| (341,140 | ) | |
| (231,846 | ) | |
| (109,294 | ) |
Transportation | |
| (33,314 | ) | |
| (14,574 | ) | |
| (18,740 | ) | |
| (63,149 | ) | |
| (31,579 | ) | |
| (31,570 | ) |
Blending
and other | |
| (67,685 | ) | |
| (52,995 | ) | |
| (14,690 | ) | |
| (131,893 | ) | |
| (112,676 | ) | |
| (19,217 | ) |
Operating
netback (1) | |
$ | 623,979 | | |
$ | 303,833 | | |
$ | 320,146 | | |
$ | 1,131,522 | | |
$ | 576,822 | | |
$ | 554,700 | |
General
and administrative | |
| (21,006 | ) | |
| (15,240 | ) | |
| (5,766 | ) | |
| (43,418 | ) | |
| (26,974 | ) | |
| (16,444 | ) |
Cash
interest | |
| (53,946 | ) | |
| (28,255 | ) | |
| (25,691 | ) | |
| (107,226 | ) | |
| (46,630 | ) | |
| (60,596 | ) |
Realized
financial derivatives (loss) gain | |
| (2,257 | ) | |
| 16,365 | | |
| (18,622 | ) | |
| 3,231 | | |
| 21,780 | | |
| (18,549 | ) |
Realized
foreign exchange loss | |
| (866 | ) | |
| (941 | ) | |
| 75 | | |
| (2,085 | ) | |
| (1,091 | ) | |
| (994 | ) |
Cash
other expense | |
| (1,025 | ) | |
| (141 | ) | |
| (884 | ) | |
| (2,096 | ) | |
| (354 | ) | |
| (1,742 | ) |
Current
income tax expense | |
| (6,475 | ) | |
| (1,350 | ) | |
| (5,125 | ) | |
| (8,155 | ) | |
| (2,470 | ) | |
| (5,685 | ) |
Cash
share-based compensation | |
| (5,565 | ) | |
| (681 | ) | |
| (4,884 | ) | |
| (15,088 | ) | |
| (10,504 | ) | |
| (4,584 | ) |
Adjusted
funds flow (2) | |
$ | 532,839 | | |
$ | 273,590 | | |
$ | 259,249 | | |
$ | 956,685 | | |
$ | 510,579 | | |
$ | 446,106 | |
Transaction
costs | |
| — | | |
| (32,832 | ) | |
| 32,832 | | |
| (1,539 | ) | |
| (41,703 | ) | |
| 40,164 | |
Exploration
and evaluation | |
| (649 | ) | |
| (369 | ) | |
| (280 | ) | |
| (667 | ) | |
| (532 | ) | |
| (135 | ) |
Depletion
and depreciation | |
| (353,101 | ) | |
| (176,144 | ) | |
| (176,957 | ) | |
| (697,238 | ) | |
| (342,143 | ) | |
| (355,095 | ) |
Non-cash
share-based compensation | |
| — | | |
| (16,237 | ) | |
| 16,237 | | |
| — | | |
| (16,237 | ) | |
| 16,237 | |
Non-cash
financing and interest | |
| (37,671 | ) | |
| (6,242 | ) | |
| (31,429 | ) | |
| (45,658 | ) | |
| (11,592 | ) | |
| (34,066 | ) |
Non-cash
other income | |
| — | | |
| — | | |
| — | | |
| — | | |
| 1,271 | | |
| (1,271 | ) |
Unrealized
financial derivatives gain (loss) | |
| 10,790 | | |
| (19,403 | ) | |
| 30,193 | | |
| (21,560 | ) | |
| (10,193 | ) | |
| (11,367 | ) |
Unrealized
foreign exchange (loss) gain | |
| (19,189 | ) | |
| 12,880 | | |
| (32,069 | ) | |
| (57,907 | ) | |
| 13,093 | | |
| (71,000 | ) |
Loss
on dispositions and swaps | |
| (6,311 | ) | |
| — | | |
| (6,311 | ) | |
| (3,650 | ) | |
| (336 | ) | |
| (3,314 | ) |
Deferred
income tax (expense) recovery | |
| (22,810 | ) | |
| 178,360 | | |
| (201,170 | ) | |
| (38,611 | ) | |
| 162,837 | | |
| (201,448 | ) |
Net
income | |
$ | 103,898 | | |
$ | 213,603 | | |
$ | (109,705 | ) | |
$ | 89,855 | | |
$ | 265,044 | | |
$ | (175,189 | ) |
(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 $532.8 million
for Q2/2024 and $956.7 million for YTD 2024 compared to $273.6 million for Q2/2023 and $510.6 million for YTD 2023. The increase in adjusted
funds flow was primarily due to higher commodity prices and production that resulted in increased revenues net of royalties, which was
offset by higher operating, transportation and blending and other expense. Cash interest and general and administrative expenses were
also higher in both periods of 2024 due to the Merger. We reported net income of $103.9 million for Q2/2024 and $89.9 million for YTD
2024 compared to net income of $213.6 million for Q2/2023 and $265.0 million for YTD 2023. The decrease in net income for Q2/2024 and
YTD 2024 relative to the same periods of 2023 is the result of deferred income tax expense recognized in 2024 compared to a deferred
tax recovery recognized in 2023, a higher depletion rate and associated depletion expense, an unrealized foreign exchange loss and increased
non-cash financing and interest costs.
| Baytex Energy Corp. Second Quarter Report 2024 | 27 |
OTHER COMPREHENSIVE INCOME
Other comprehensive income is comprised of
the foreign currency translation adjustment on U.S. net assets which is not recognized in net income or loss. The foreign currency translation
gain of $52.0 million for Q2/2024 and $162.6 million for YTD 2024 relates to the change in value of our U.S. net assets and is due to
the weakening of the Canadian dollar relative to the U.S. dollar at June 30, 2024 compared to March 31, 2024 and December 31, 2023. The
CAD/USD exchange rate was 1.3687 CAD/ USD as at June 30, 2024 compared to 1.3533 CAD/USD at March 31, 2024 and 1.3205 CAD/USD at December
31, 2023.
CAPITAL EXPENDITURES
Capital expenditures for the three and six months ended June 30, 2024
and 2023 are summarized as follows.
| |
Three
Months Ended June 30 | |
| |
2024 | | |
2023 | |
($
thousands) | |
Canada | | |
U.S. | | |
Total | | |
Canada | | |
U.S. | | |
Total | |
Drilling,
completion and equipping | |
$ | 80,349 | | |
$ | 208,662 | | |
$ | 289,011 | | |
$ | 77,518 | | |
$ | 69,309 | | |
$ | 146,827 | |
Facilities
and other | |
| 21,567 | | |
| 28,995 | | |
| 50,562 | | |
| 18,885 | | |
| 4,992 | | |
| 23,877 | |
Exploration
and development expenditures | |
$ | 101,916 | | |
$ | 237,657 | | |
$ | 339,573 | | |
$ | 96,403 | | |
$ | 74,301 | | |
$ | 170,704 | |
Property
acquisitions | |
$ | 1,802 | | |
$ | 1,547 | | |
$ | 3,349 | | |
$ | (62 | ) | |
$ | — | | |
$ | (62 | ) |
Proceeds
from dispositions | |
$ | 157 | | |
$ | (2,852 | ) | |
$ | (2,695 | ) | |
$ | (50 | ) | |
$ | — | | |
$ | (50 | ) |
| |
Six
Months Ended June 30 | |
| |
2024 | | |
2023 | |
($
thousands) | |
Canada | | |
U.S. | | |
Total | | |
Canada | | |
U.S. | | |
Total | |
Drilling,
completion and equipping | |
$ | 206,357 | | |
$ | 428,601 | | |
$ | 634,958 | | |
$ | 232,471 | | |
$ | 118,145 | | |
$ | 350,616 | |
Facilities
and other | |
| 53,685 | | |
| 63,481 | | |
| 117,166 | | |
| 48,538 | | |
| 5,176 | | |
| 53,714 | |
Exploration
and development expenditures | |
$ | 260,042 | | |
$ | 492,082 | | |
$ | 752,124 | | |
$ | 281,009 | | |
$ | 123,321 | | |
$ | 404,330 | |
Property
acquisitions | |
$ | 36,077 | | |
$ | 2,675 | | |
$ | 38,752 | | |
$ | 444 | | |
$ | — | | |
$ | 444 | |
Proceeds
from dispositions | |
$ | 132 | | |
$ | (2,852 | ) | |
$ | (2,720 | ) | |
$ | (285 | ) | |
$ | — | | |
$ | (285 | ) |
Exploration and development expenditures were
$339.6 million for Q2/2024 and $752.1 million for YTD 2024 compared to $170.7 million for Q2/2023 and $404.3 million for YTD 2023. Exploration
and development expenditures in Q2/2024 and YTD 2024 were higher compared to Q2/2023 and YTD 2023 primarily due to development activity
on the properties acquired from Ranger. We also completed property acquisitions, including the acquisition of 30.75 net sections of high-quality
Duvernay lands adjacent to our existing acreage, in YTD 2024 for a total of $38.8 million.
In Canada, exploration and development expenditures
were $101.9 million in Q2/2024 and $260.0 million for YTD 2024 compared to $96.4 million in Q2/2023 and $281.0 million for YTD 2023.
Drilling and completion spending of $80.3 million in Q2/2024 was relatively consistent with Q2/2023 when we spent $77.5 million which
reflects similar development activity levels on our Canadian properties. YTD 2024 drilling and completion spending of $206.4 million
reflects lower light and heavy oil development activity relative to YTD 2023 when we spent $232.5 million. We also invested $53.7 million
on facilities and other expenditures during YTD 2024 which is consistent with $48.5 million during YTD 2023.
Total U.S. exploration and development expenditures
were $237.7 million for Q2/2024 and $492.1 million for YTD 2024 compared to $74.3 million in Q2/2023 and $123.3 million for YTD 2023.
The increase in exploration and development expenditures for both periods of 2024 is due to development activity on our properties acquired
from Ranger.
Exploration and development expenditures of $752.1
million for YTD 2024 were consistent with expectations. Our annual guidance of $1.2 - $1.3 billion reflects moderated exploration and
development spending over the remainder of 2024.
CAPITAL RESOURCES AND LIQUIDITY
Our capital management objective is to maintain
a strong balance sheet that provides financial flexibility to execute our development programs, provide returns to shareholders and optimize
our portfolio through strategic acquisitions. We strive to actively manage our capital structure in response to changes in economic conditions.
At June 30, 2024, our capital structure was comprised of shareholders' capital, long-term notes, trade receivables, prepaids and
other assets, trade payables, dividends payable, share-based compensation liability, other long-term liabilities, cash and the credit
facilities.
28 | Baytex Energy Corp. Second Quarter Report 2024 | |
In order to manage our capital structure and
liquidity, we may from time to time issue or repurchase equity or debt securities, enter into business transactions including the sale
of assets or adjust capital spending to manage current and projected debt levels. There is no certainty that any of these additional
sources of capital would be available if required.
Management of debt levels is a priority for Baytex
in order to sustain operations and support our business strategy. Net debt(1) of $2.6 billion at June 30, 2024 was
consistent with $2.5 billion at December 31, 2023 which was due to the impact of a weaker Canadian dollar at June 30, 2024
on our U.S. dollar denominated debt and also reflects $38.8 million of property acquisitions along with $49.7 million of debt issuance
costs incurred during YTD 2024. We expect net debt to decline over the remainder of 2024 as we continue to allocate 50% of free cash
flow to the balance sheet.
| (1) | Capital
management measure. Refer to the Specified Financial Measures section in this MD&A for
further information. |
Credit Facilities
At June 30, 2024, we had $626.0 million
of principal amount outstanding under our revolving credit facilities which total US$1.1 billion ($1.5 billion) (the "Credit Facilities").
The Credit Facilities are secured and are comprised of a US$50 million operating loan and a US$750 million syndicated revolving loan
for Baytex and a US$45 million operating loan and a US$255 million syndicated revolving loan for Baytex's wholly-owned subsidiary, Baytex
Energy USA, Inc. On May 9, 2024, we extended the maturity of the Credit Facilities from April 1, 2026 to May 9, 2028.
There were no changes to the loan balances or financial covenants as a result of the amendment. Following the amendment, borrowing in
Canadian funds previously based on the banker's acceptance rate has been replaced with borrowings based on the Canadian Overnight Repo
Rate Average ("CORRA").
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, CORRA rates or secured overnight financing rates ("SOFR"), plus applicable margins.
The weighted average interest rate on the Credit
Facilities was 7.9% for Q2/2024 and 8.0% for YTD 2024 compared to 6.8% for Q2/2023 and 6.5% for YTD 2023. The increase in the weighted
average interest rate on our Credit Facilities was primarily due to an increase in the margins applicable to our Credit Facilities in
2024 relative to the same period in 2023.
At June 30, 2024, we had $5.7 million of
outstanding letters of credit (December 31, 2023 - $5.6 million outstanding) under the Credit Facilities.
The agreements and associated amending agreements
relating to the Credit Facilities are accessible on the SEDAR+ website at www.sedarplus.ca and through the U.S. Securities and Exchange
Commission at www.sec.gov.
Financial Covenants
The following table summarizes the financial
covenants applicable to the Credit Facilities and our compliance therewith at June 30, 2024.
| |
| Position
as at June | | |
| | |
Covenant
Description | |
| 30,
2024 | | |
| Covenant | |
Senior
Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio) | |
| 0.3:1.0 | | |
| 3.5:1.0 | |
Interest
Coverage (3) (Minimum Ratio) | |
| 10.3:1.0 | | |
| 3.5:1.0 | |
Total
Debt (4) to Bank EBITDA (2) (Maximum Ratio) | |
| 1.1:1.0 | | |
| 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, 2024, the Company's Senior Secured Debt totaled $630.6 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, 2024 was
$2.3 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, 2024 was $219.0 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 payables, share-based compensation liability,
dividends payable, asset retirement obligations, leases, deferred income tax liabilities,
other long-term liabilities and financial derivative liabilities. As at June 30, 2024,
the Company's Total Debt totaled $2.5 billion of principal amounts outstanding. |
| Baytex Energy Corp. Second Quarter Report 2024 | 29 |
Long-Term Notes
At June 30, 2024 we have two issuances of
long-term notes outstanding with a total principal amount of $1.9 billion. The long-term notes do not contain any financial maintenance
covenants.
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 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. At June 30, 2024 there was
US$800.0 million aggregate principal amount of the 8.50% Senior Notes outstanding.
On April 1, 2024, we closed a private offering
of the US$575 million aggregate principal amount of senior unsecured notes due 2032 ("7.375% Senior Notes"). The 7.375% Senior
Notes were priced at 99.266% of par to yield 7.500% per annum, bear interest at a rate of 7.375% per annum and mature on March 15,
2032. The 7.375% Senior Notes are redeemable at our option, in whole or in part, at specified redemption prices on or after March 15,
2027 and will be redeemable at par from March 15, 2029 to maturity. Proceeds from the 7.375% Senior Notes were used to redeem the
remaining US$409.8 million aggregate principal amount of the outstanding 8.75% Senior Notes at 104.375% of par value, pay the related
fees and expenses associated with the offering, and repay a portion of the debt outstanding on our Credit Facilities. At June 30,
2024 there was US$575.0 million aggregate principal amount of the 7.375% Senior Notes outstanding.
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, 2024, we issued 0.3 million common shares pursuant to our share-based compensation program. As at June 30,
2024, we had 805.0 million common shares issued and outstanding and no preferred shares issued and outstanding.
Our shareholder returns framework includes common
share repurchases and a quarterly dividend. During the six months ended June 30, 2024, we repurchased 17.0 million common shares
under our normal course issuer bid ("NCIB") at an average price of $4.85 per share for total consideration of $82.3 million.
In June 2024, we renewed our NCIB under which Baytex is permitted to purchase for cancellation up to 70.1 million common shares
over the 12-month period commencing July 2, 2024, which represents 10% of Baytex's public float, as defined by the TSX, as of June 18,
2024. Baytex obtained an exemption order from the Canadian securities regulators which permits the company to purchase its common shares
through the NYSE and other U.S.-based trading systems.
Effective January 1, 2024, the Government
of Canada introduced a 2% federal tax on equity repurchases. During the six months ended June 30, 2024, Baytex recorded a $1.6 million
liability, charged to shareholders’ capital, related to the federal tax on equity repurchases.
On January 2, April 1 and July 2,
2024, we paid a quarterly cash dividend of CDN$0.0225 per share to shareholders of record. On July 25, 2024, the Company's Board
of Directors declared a quarterly cash dividend of $0.0225 per share to be paid on October 1, 2024 for shareholders on record as
at September 16, 2024. These dividends are designated as “eligible dividends” for Canadian income tax purposes. For
U.S. income tax purposes, Baytex’s dividends are considered “qualified dividends.”
30 | Baytex Energy Corp. Second Quarter Report 2024 | |
Contractual Obligations
We have a number of financial obligations that
are incurred in the ordinary course of business. A significant portion of these obligations will be funded by adjusted funds flow. These
obligations as of June 30, 2024 and the expected timing for funding these obligations are noted in the table below.
($
thousands) | |
Total | | |
Less
than 1 year | | |
1-3
years | | |
3-5
years | | |
Beyond
5 years | |
Financial
derivatives | |
$ | 5,314 | | |
$ | 5,314 | | |
$ | — | | |
$ | — | | |
$ | — | |
Credit
facilities - principal | |
| 625,976 | | |
| — | | |
| — | | |
| 625,976 | | |
| — | |
Long-term
notes - principal | |
| 1,881,894 | | |
| — | | |
| — | | |
| — | | |
| 1,881,894 | |
Interest
on long-term notes (1) | |
| 990,729 | | |
| 151,108 | | |
| 302,215 | | |
| 302,215 | | |
| 235,191 | |
Lease
obligations - principal | |
| 31,351 | | |
| 10,189 | | |
| 10,188 | | |
| 7,269 | | |
| 3,705 | |
Processing
agreements | |
| 5,334 | | |
| 559 | | |
| 908 | | |
| 3,867 | | |
| — | |
Transportation
agreements | |
| 188,871 | | |
| 53,196 | | |
| 89,161 | | |
| 37,860 | | |
| 8,654 | |
Total | |
$ | 3,729,469 | | |
$ | 220,366 | | |
$ | 402,472 | | |
$ | 977,187 | | |
$ | 2,129,444 | |
| (1) | 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. The present value of the future
estimated abandonment and reclamation costs are included in the asset retirement obligations presented in the statement of financial
position. Programs to abandon and reclaim well sites and facilities are undertaken regularly in accordance with applicable legislative
requirements.
| Baytex Energy Corp. Second Quarter Report 2024 | 31 |
QUARTERLY FINANCIAL INFORMATION
($ thousands, except per common
share | |
2024 | | |
2023 | | |
2022 | |
amounts) | |
Q2 | | |
Q1 | | |
Q4 | | |
Q3 | | |
Q2 | | |
Q1 | | |
Q4 | | |
Q3 | |
Petroleum and natural gas sales | |
| 1,133,123 | | |
| 984,192 | | |
| 1,065,515 | | |
| 1,163,010 | | |
| 598,760 | | |
| 555,336 | | |
| 648,986 | | |
| 712,065 | |
Net income (loss) | |
| 103,898 | | |
| (14,043 | ) | |
| (625,830 | ) | |
| 127,430 | | |
| 213,603 | | |
| 51,441 | | |
| 352,807 | | |
| 264,968 | |
Per common share - basic | |
| 0.13 | | |
| (0.02 | ) | |
| (0.75 | ) | |
| 0.15 | | |
| 0.37 | | |
| 0.09 | | |
| 0.65 | | |
| 0.48 | |
Per common share - diluted | |
| 0.13 | | |
| (0.02 | ) | |
| (0.75 | ) | |
| 0.15 | | |
| 0.36 | | |
| 0.09 | | |
| 0.64 | | |
| 0.47 | |
Adjusted funds flow (1) | |
| 532,839 | | |
| 423,846 | | |
| 502,148 | | |
| 581,623 | | |
| 273,590 | | |
| 236,989 | | |
| 255,552 | | |
| 284,288 | |
Per common share - basic | |
| 0.65 | | |
| 0.52 | | |
| 0.60 | | |
| 0.68 | | |
| 0.47 | | |
| 0.43 | | |
| 0.47 | | |
| 0.51 | |
Per common share - diluted | |
| 0.65 | | |
| 0.52 | | |
| 0.60 | | |
| 0.68 | | |
| 0.47 | | |
| 0.43 | | |
| 0.46 | | |
| 0.51 | |
Free cash flow (2) | |
| 180,673 | | |
| (88 | ) | |
| 290,785 | | |
| 158,440 | | |
| 96,313 | | |
| (1,918 | ) | |
| 143,324 | | |
| 111,568 | |
Per common share - basic | |
| 0.22 | | |
| — | | |
| 0.35 | | |
| 0.19 | | |
| 0.17 | | |
| — | | |
| 0.26 | | |
| 0.20 | |
Per common share - diluted | |
| 0.22 | | |
| — | | |
| 0.35 | | |
| 0.18 | | |
| 0.16 | | |
| — | | |
| 0.26 | | |
| 0.20 | |
Cash flows from operating activities | |
| 505,584 | | |
| 383,773 | | |
| 474,452 | | |
| 444,033 | | |
| 192,308 | | |
| 184,938 | | |
| 303,441 | | |
| 310,423 | |
Per common share - basic | |
| 0.62 | | |
| 0.47 | | |
| 0.57 | | |
| 0.52 | | |
| 0.33 | | |
| 0.34 | | |
| 0.56 | | |
| 0.56 | |
Per common share - diluted | |
| 0.62 | | |
| 0.47 | | |
| 0.57 | | |
| 0.52 | | |
| 0.33 | | |
| 0.34 | | |
| 0.55 | | |
| 0.56 | |
Dividends declared | |
| 18,161 | | |
| 18,494 | | |
| 18,381 | | |
| 19,138 | | |
| — | | |
| — | | |
| — | | |
| — | |
Per common share | |
| 0.0225 | | |
| 0.0225 | | |
| 0.0225 | | |
| 0.0225 | | |
| — | | |
| — | | |
| — | | |
| — | |
Exploration and development | |
| 339,573 | | |
| 412,551 | | |
| 199,214 | | |
| 409,191 | | |
| 170,704 | | |
| 233,626 | | |
| 103,634 | | |
| 167,453 | |
Canada | |
| 101,916 | | |
| 158,126 | | |
| 75,137 | | |
| 107,053 | | |
| 96,403 | | |
| 184,606 | | |
| 85,641 | | |
| 117,150 | |
U.S. | |
| 237,657 | | |
| 254,425 | | |
| 124,077 | | |
| 302,138 | | |
| 74,301 | | |
| 49,020 | | |
| 17,993 | | |
| 50,303 | |
Property acquisitions | |
| 3,349 | | |
| 35,403 | | |
| 33,923 | | |
| 4,277 | | |
| (62 | ) | |
| 506 | | |
| 1,085 | | |
| — | |
Proceeds from dispositions | |
| (2,695 | ) | |
| (25 | ) | |
| (159,745 | ) | |
| (226 | ) | |
| (50 | ) | |
| (235 | ) | |
| (148 | ) | |
| (25,460 | ) |
Net debt (1) | |
| 2,639,014 | | |
| 2,639,841 | | |
| 2,534,287 | | |
| 2,824,348 | | |
| 2,814,844 | | |
| 995,170 | | |
| 987,446 | | |
| 1,113,559 | |
Total assets | |
| 7,770,926 | | |
| 7,717,495 | | |
| 7,460,931 | | |
| 8,946,181 | | |
| 8,617,444 | | |
| 5,180,059 | | |
| 5,103,769 | | |
| 4,923,617 | |
Common shares outstanding | |
| 804,977 | | |
| 821,322 | | |
| 821,681 | | |
| 845,360 | | |
| 862,192 | | |
| 545,553 | | |
| 544,930 | | |
| 547,615 | |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Daily production | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Total production (boe/d) | |
| 154,194 | | |
| 150,620 | | |
| 160,373 | | |
| 150,600 | | |
| 89,761 | | |
| 86,760 | | |
| 86,864 | | |
| 83,194 | |
Canada (boe/d) | |
| 63,688 | | |
| 62,081 | | |
| 64,744 | | |
| 63,289 | | |
| 55,874 | | |
| 60,651 | | |
| 56,946 | | |
| 55,803 | |
U.S. (boe/d) | |
| 90,506 | | |
| 88,540 | | |
| 95,629 | | |
| 87,311 | | |
| 33,887 | | |
| 26,109 | | |
| 29,918 | | |
| 27,391 | |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Benchmark prices | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
WTI oil (US$/bbl) | |
| 80.57 | | |
| 76.96 | | |
| 78.32 | | |
| 82.26 | | |
| 73.78 | | |
| 76.13 | | |
| 82.64 | | |
| 91.56 | |
WCS heavy oil ($/bbl) | |
| 91.72 | | |
| 77.73 | | |
| 76.86 | | |
| 93.02 | | |
| 78.85 | | |
| 69.44 | | |
| 77.37 | | |
| 93.62 | |
Edmonton par oil ($/bbl) | |
| 105.30 | | |
| 92.16 | | |
| 99.72 | | |
| 107.93 | | |
| 95.13 | | |
| 99.04 | | |
| 109.57 | | |
| 116.79 | |
CAD/USD avg exchange rate | |
| 1.3684 | | |
| 1.3488 | | |
| 1.3619 | | |
| 1.3410 | | |
| 1.3431 | | |
| 1.3520 | | |
| 1.3577 | | |
| 1.3059 | |
AECO natural gas ($/mcf) | |
| 1.44 | | |
| 2.05 | | |
| 2.66 | | |
| 2.39 | | |
| 2.35 | | |
| 4.34 | | |
| 5.58 | | |
| 5.81 | |
NYMEX natural gas (US$/mmbtu) | |
| 1.89 | | |
| 2.24 | | |
| 2.88 | | |
| 2.55 | | |
| 2.10 | | |
| 3.42 | | |
| 6.26 | | |
| 8.20 | |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Total sales, net of blending and other
expense ($/boe) (2) | |
| 75.93 | | |
| 67.12 | | |
| 68.00 | | |
| 80.34 | | |
| 66.82 | | |
| 63.48 | | |
| 74.93 | | |
| 87.68 | |
Royalties ($/boe) (3) | |
| (17.14 | ) | |
| (15.26 | ) | |
| (15.49 | ) | |
| (17.33 | ) | |
| (13.21 | ) | |
| (11.94 | ) | |
| (15.23 | ) | |
| (19.21 | ) |
Operating expense ($/boe) (3) | |
| (11.95 | ) | |
| (12.65 | ) | |
| (11.17 | ) | |
| (12.57 | ) | |
| (14.62 | ) | |
| (14.40 | ) | |
| (13.06 | ) | |
| (14.39 | ) |
Transportation expense ($/boe) (3) | |
| (2.37 | ) | |
| (2.18 | ) | |
| (2.02 | ) | |
| (2.02 | ) | |
| (1.78 | ) | |
| (2.18 | ) | |
| (1.85 | ) | |
| (1.67 | ) |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Operating netback ($/boe) (2) | |
| 44.47 | | |
| 37.03 | | |
| 39.32 | | |
| 48.42 | | |
| 37.21 | | |
| 34.96 | | |
| 44.79 | | |
| 52.41 | |
Financial derivatives (loss) gain ($/boe)
(3) | |
| (0.16 | ) | |
| 0.40 | | |
| 0.84 | | |
| 0.15 | | |
| 2.00 | | |
| 0.69 | | |
| (6.21 | ) | |
| (9.98 | ) |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Operating netback after financial
derivatives ($/boe) (2) | |
| 44.31 | | |
| 37.43 | | |
| 40.16 | | |
| 48.57 | | |
| 39.21 | | |
| 35.65 | | |
| 38.58 | | |
| 42.43 | |
| (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) | Calculated as royalties, operating
expense, transportation expense or financial derivatives gain or loss divided by barrels
of oil equivalent production volume for the applicable period. |
32 | Baytex Energy Corp. Second Quarter Report 2024 | |
Our results for the previous eight quarters reflect
the disciplined execution of our capital programs as oil and natural gas prices have fluctuated. Production steadily increased from 83,194
boe/d in Q3/2022 and reached 154,194 boe/d in Q2/2024 due to strong well performance from our development programs in Canada and the
U.S., along with the production contribution from the Merger with Ranger.
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 is reflected in our realized sales price of $87.68/boe for Q3/2022, which is our strongest realized pricing in the most recent eight
quarters. Our realized price of $75.93/boe for Q2/2024 reflects stable crude oil prices from balanced global supply and demand with ongoing
geopolitical tensions.
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
$532.8 million and cash flows from operating activities of $505.6 million for Q2/2024 reflect strong production results from our development
plans in the U.S. and Canada as well as the Merger with Ranger.
Net debt can fluctuate on a quarterly basis depending
on the timing of exploration and development expenditures, changes in our adjusted funds flow and the closing CAD/USD exchange rate which
is used to translate our U.S. dollar denominated debt. Net debt(1) increased to $2.6 billion at Q2/2024 from $1.1 billion
at Q3/2022 as a result of additional debt used to fund the Merger which closed in Q2/2023. The change in net debt also reflects free
cash flow(2) of $867.5 million generated in the period since Q3/2022, of which $397.7 million was allocated to shareholder
returns.
| (1) | Capital management measure. Refer to the Specified Financial
Measures section in this MD&A for further information. |
| (2) | Specified financial measure that
does not have any standardized meaning prescribed by IFRS and may not be comparable with
the calculation of similar measures presented by other entities. Refer to the Specified Financial
Measures section in this MD&A for further information. |
ENVIRONMENTAL REGULATIONS
As a result of our involvement in the exploration
for and production of oil and natural gas we are subject to various emissions, carbon and other environmental regulations. Refer to the
AIF for the year ended December 31, 2023 for a full description of the risks associated with these regulations and how they may
impact our business in the future.
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 ("ISSB") has issued an IFRS Sustainability Disclosure Standard with the objective to develop a global framework for environmental
sustainability disclosure. The Canadian Sustainability Standards Board has released proposed standards that are aligned with the ISSB
release, but include suggestions for Canadian-specific modifications. 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.
OFF BALANCE SHEET TRANSACTIONS
We do not have any financial arrangements that
are excluded from the consolidated financial statements as at June 30, 2024, 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, 2024. 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, 2023.
CHANGES IN ACCOUNTING POLICIES
Effective January 1, 2024, Baytex adopted
amendments to IAS 1 Presentation of Financial Statements which was issued by the IASB in January 2020. The amendments further
clarify the requirements for the presentation of liabilities as current or non-current in the consolidated statements of financial position.
These amendments have not had a material impact on our consolidated
financial statements.
| Baytex Energy Corp. Second Quarter Report 2024 | 33 |
SPECIFIED FINANCIAL MEASURES
In
this MD&A, we refer to certain specified financial measures (such as free cash flow, operating netback, total sales, net of blending
and other expense, heavy oil sales, net of blending and other expense, and average royalty rate which do not have any standardized meaning
prescribed by IFRS. While these measures are commonly used in the oil and natural gas industry, our determination of these measures may
not be comparable with calculations of similar measures presented by other reporting issuers. This MD&A also contains the terms "adjusted
funds flow" and "net debt" which are capital management measures. We believe that inclusion of these specified financial
measures provides useful information to financial statement users when evaluating the financial results of Baytex.
Non-GAAP Financial Measures
Total sales, net of blending and other expense and heavy oil, net
of blending and other expense
Total
sales, net of blending and other expense and heavy oil, net of blending and other expense represent the total revenues and heavy oil
revenues realized from produced volumes during a period, respectively. Total sales, net of blending and other expense is comprised of
total petroleum and natural gas sales adjusted for blending and other expense. Heavy oil, net of blending and other expense is calculated
as heavy oil sales less blending and other expense. We believe including the blending and other expense associated with purchased volumes
is useful when analyzing our realized pricing for produced volumes against benchmark commodity prices.
The
following table reconciles heavy oil, net of blending and other expense to amounts disclosed in the primary financial statements in the
following table.
| |
Three
Months Ended June 30 | | |
Six
Months Ended June 30 | |
($ thousands) | |
2024 | | |
2023 | | |
2024 | | |
2023 | |
Petroleum and natural gas sales | |
$ | 1,133,123 | | |
$ | 598,760 | | |
$ | 2,117,315 | | |
$ | 1,154,096 | |
Light oil and condensate (1) | |
| (662,650 | ) | |
| (308,810 | ) | |
| (1,263,765 | ) | |
| (597,275 | ) |
NGL (1) | |
| (49,510 | ) | |
| (20,163 | ) | |
| (95,441 | ) | |
| (41,997 | ) |
Natural gas sales (1) | |
| (26,003 | ) | |
| (18,338 | ) | |
| (58,225 | ) | |
| (46,290 | ) |
Heavy oil sales | |
$ | 394,960 | | |
$ | 251,449 | | |
$ | 699,884 | | |
$ | 468,534 | |
Blending and other expense (2) | |
| (67,685 | ) | |
| (52,995 | ) | |
| (131,893 | ) | |
| (112,676 | ) |
Heavy oil, net of blending and
other expense | |
$ | 327,275 | | |
$ | 198,454 | | |
$ | 567,991 | | |
$ | 355,858 | |
| (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, 2024 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.
34 | Baytex Energy Corp. Second Quarter Report 2024 | |
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) | |
2024 | | |
2023 | | |
2024 | | |
2023 | |
Petroleum and natural gas sales | |
$ | 1,133,123 | | |
$ | 598,760 | | |
$ | 2,117,315 | | |
$ | 1,154,096 | |
Blending and other expense | |
| (67,685 | ) | |
| (52,995 | ) | |
| (131,893 | ) | |
| (112,676 | ) |
Total sales, net of blending and other expense | |
| 1,065,438 | | |
| 545,765 | | |
| 1,985,422 | | |
| 1,041,420 | |
Royalties | |
| (240,440 | ) | |
| (107,920 | ) | |
| (449,611 | ) | |
| (201,173 | ) |
Operating expense | |
| (167,705 | ) | |
| (119,438 | ) | |
| (341,140 | ) | |
| (231,846 | ) |
Transportation expense | |
| (33,314 | ) | |
| (14,574 | ) | |
| (63,149 | ) | |
| (31,579 | ) |
Operating netback | |
$ | 623,979 | | |
$ | 303,833 | | |
$ | 1,131,522 | | |
$ | 576,822 | |
Realized financial derivatives (loss)
gain (1) | |
| (2,257 | ) | |
| 16,365 | | |
| 3,231 | | |
| 21,780 | |
Operating netback after realized financial
derivatives | |
$ | 621,722 | | |
$ | 320,198 | | |
$ | 1,134,753 | | |
$ | 598,602 | |
| (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, 2024 for further information. |
Free cash flow
We use free cash flow to evaluate our financial
performance and to assess the cash available for debt repayment, common share repurchases, dividends and acquisition opportunities. Free
cash flow is comprised of cash flows from operating activities adjusted for changes in non-cash working capital, additions to exploration
and evaluation assets, additions to oil and gas properties, payments on lease obligations, transaction costs and cash premiums on derivatives.
Free cash flow is reconciled to cash flows from operating activities
in the following table.
| |
Three
Months Ended June 30 | | |
Six
Months Ended June 30 | |
($ thousands) | |
2024 | | |
2023 | | |
2024 | | |
2023 | |
Cash flows from operating activities | |
$ | 505,584 | | |
$ | 192,308 | | |
$ | 889,357 | | |
$ | 377,246 | |
Change in non-cash working capital | |
| 20,140 | | |
| 40,795 | | |
| 52,163 | | |
| 79,849 | |
Additions to exploration and evaluation assets | |
| — | | |
| (741 | ) | |
| — | | |
| (1,231 | ) |
Additions to oil and gas properties | |
| (339,573 | ) | |
| (169,963 | ) | |
| (752,124 | ) | |
| (403,099 | ) |
Payments on lease obligations | |
| (5,478 | ) | |
| (1,181 | ) | |
| (10,350 | ) | |
| (2,336 | ) |
Transaction costs | |
| — | | |
| 32,832 | | |
| 1,539 | | |
| 41,703 | |
Cash premiums on derivatives | |
| — | | |
| 2,263 | | |
| — | | |
| 2,263 | |
Free cash flow | |
$ | 180,673 | | |
$ | 96,313 | | |
$ | 180,585 | | |
$ | 94,395 | |
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.
| Baytex Energy Corp. Second Quarter Report 2024 | 35 |
Operating netback per boe
Operating netback per boe is operating netback
(a non-GAAP financial measure) divided by barrels of oil equivalent production volume for the applicable period and is used to assess
our operating performance on a unit of production basis. Realized financial derivative gains and losses per boe are added to operating
netback per boe to arrive at operating netback after financial derivatives per boe. Realized financial derivatives gains and losses are
added to operating netback to provide a more complete picture of our financial performance as our financial derivatives are used to provide
price certainty on a portion of our production.
Capital Management Measures
Net debt
We use net debt to monitor our current financial
position and to evaluate existing sources of liquidity. We also use net debt projections to estimate future liquidity and whether additional
sources of capital are required to fund ongoing operations. Net debt is comprised of our credit facilities and long-term notes outstanding
adjusted for unamortized debt issuance costs, trade payables, share-based compensation liability, dividends payable, other long-term
liabilities, cash, trade receivables, and prepaids and other assets.
The following table summarizes our calculation of net debt.
| |
As at | |
($ thousands) | |
June 30,
2024 | | |
December 31,
2023 | |
Credit facilities | |
$ | 607,589 | | |
$ | 848,749 | |
Unamortized
debt issuance costs - Credit facilities (1) | |
| 18,387 | | |
| 15,987 | |
Long-term notes | |
| 1,833,182 | | |
| 1,562,361 | |
Unamortized
debt issuance costs - Long-term notes (1) | |
| 48,712 | | |
| 35,114 | |
Trade payables | |
| 617,222 | | |
| 477,295 | |
Share-based compensation liability | |
| 22,706 | | |
| 35,732 | |
Dividends payable | |
| 18,161 | | |
| 18,381 | |
Other long-term liabilities | |
| 19,845 | | |
| 19,147 | |
Cash | |
| (35,887 | ) | |
| (55,815 | ) |
Trade receivables | |
| (429,098 | ) | |
| (339,405 | ) |
Prepaids and other assets | |
| (81,805 | ) | |
| (83,259 | ) |
Net debt | |
$ | 2,639,014 | | |
$ | 2,534,287 | |
| (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, 2024. These amounts
represent the remaining balance of costs that were paid by Baytex at the inception of the
contract. |
Adjusted funds flow
Adjusted funds flow is used to monitor operating
performance and the Company's ability to generate funds for exploration and development expenditures and settlement of abandonment obligations.
Adjusted funds flow is comprised of cash flows from operating activities adjusted for changes in non-cash working capital, asset retirements
obligations settled during the applicable period, transaction costs and cash premiums on derivatives.
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) | |
2024 | | |
2023 | | |
2024 | | |
2023 | |
Cash flow from operating activities | |
$ | 505,584 | | |
$ | 192,308 | | |
$ | 889,357 | | |
$ | 377,246 | |
Change in non-cash working capital | |
| 20,140 | | |
| 40,795 | | |
| 52,163 | | |
| 79,849 | |
Asset retirement obligations settled | |
| 7,115 | | |
| 5,392 | | |
| 13,626 | | |
| 9,518 | |
Transaction costs | |
| — | | |
| 32,832 | | |
| 1,539 | | |
| 41,703 | |
Cash premiums on derivatives | |
| — | | |
| 2,263 | | |
| — | | |
| 2,263 | |
Adjusted funds flow | |
$ | 532,839 | | |
$ | 273,590 | | |
$ | 956,685 | | |
$ | 510,579 | |
36 | Baytex Energy Corp. Second Quarter Report 2024 | |
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 that changes were made to, internal controls over financial reporting during the three months ended June 30,
2024, except for the matter described below.
Baytex previously excluded business processes
acquired through the Merger on June 20, 2023 from the Company's evaluation of internal control over financial reporting as permitted
by applicable securities laws in Canada and the U.S. We completed the evaluation of design of internal controls over financial reporting
of Ranger during Q2/2024.
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: that we can effectively allocate capital across our assets; our expectation that net debt will
decline over the balance of 2024; our 2024 guidance for: exploration and development expenditures, average daily production, royalty rate
and operating expense, transportation expense, general and administrative expense, cash interest expense, current income taxes, lease
expenditures and asset retirement obligations settled; the existence, operation and strategy of our risk management program; that we intend
to settle outstanding share based compensation awards in cash; the expected time to resolve the reassessment of our tax filings by the
Canada Revenue Agency; our objective to maintain a strong balance sheet to execute development programs, deliver shareholder returns and
optimize our portfolio through strategic acquisitions; that we may issue or repurchase debt or equity securities from time to time; our
intent to fund certain financial obligations with cash flow from operations and the expected timing of the financial obligations. In addition,
information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based
on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that the reserves can
be profitably produced in the future. In addition, information and statements relating to reserves are deemed to be forward-looking statements,
as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted
or estimated, and that the reserves can be profitably produced in the future.
These forward-looking statements are based
on certain key assumptions regarding, among other things: oil and natural gas prices and differentials between light, medium and heavy
crude oil prices; well production rates and reserve volumes; our ability to add production and reserves through our exploration and development
activities; capital expenditure levels; our ability to borrow under our credit agreements; the receipt, in a timely manner, of regulatory
and other required approvals for our operating activities; the availability and cost of labour and other industry services; interest and
foreign exchange rates; the continuance of existing and, in certain circumstances, proposed tax and royalty regimes; our ability to develop
our crude oil and natural gas properties in the manner currently contemplated; that we will have sufficient financial resources in the
future to provide shareholder returns; and current industry conditions, laws and regulations continuing in effect (or, where changes are
proposed, such changes being adopted as anticipated). Readers are cautioned that such assumptions, although considered reasonable by Baytex
at the time of preparation, may prove to be incorrect.
Actual results achieved will vary from the
information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include,
but are not limited to: the risk of an extended period of low oil and natural gas prices; risks associated with our ability to develop
our properties and add reserves; that we may not achieve the expected benefits of acquisitions and we may sell assets below their carrying
value; the availability and cost of capital or borrowing; restrictions or costs imposed by climate change initiatives and the physical
risks of climate change; the impact of an energy transition on demand for petroleum productions; availability and cost of gathering, processing
and pipeline systems; retaining or replacing our leadership and key personnel; changes in income tax or other laws or government incentive
programs; risks associated with large projects; risks associated with higher a higher concentration of activity and tighter drilling spacing;
costs to develop and operate our properties; current or future controls, legislation or regulations; restrictions on or access to water
or other fluids; public perception and its influence on the regulatory regime; new regulations on hydraulic fracturing; regulations regarding
the disposal of fluids; risks associated with our hedging activities; variations in interest rates and foreign exchange rates; uncertainties
associated with estimating oil and natural gas reserves; our inability to fully insure against all risks; risks associated with a third-party
operating our Eagle Ford properties; additional risks associated with our thermal heavy crude oil projects; our ability to compete with
other organizations in the oil and gas industry; risks associated with our use of information technology systems; adverse results of litigation;
that our Credit Facilities may not provide sufficient liquidity or may not be renewed; failure to comply with the covenants in our debt
agreements; risks associated with expansion into new activities; the impact of Indigenous claims; risks of counterparty default; impact
of geopolitical risk and conflicts; loss of foreign private issuer status; conflicts of interest between the Company and its directors
and officers; variability of share buybacks and dividends; risks associated with the ownership of our securities, including changes in
market-based factors; risks for United States and other non-resident shareholders, including the ability to enforce civil remedies, differing
practices for reporting reserves and production, additional taxation applicable to non-residents and foreign exchange risk; and other
factors, many of which are beyond our control. These and additional risk factors are discussed in our Annual Information Form, Annual
Report on Form 40-F and Management's Discussion and Analysis for the year ended December 31, 2023, 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.
| Baytex Energy Corp. Second Quarter Report 2024 | 37 |
The future acquisition of our common shares
pursuant to a share buyback (including through its NCIB), if any, and the level thereof is uncertain. Any decision to acquire Common Shares
pursuant to a share buyback will be subject to the discretion of the Board and may depend on a variety of factors, including, without
limitation, the Corporation's business performance, financial condition, financial requirements, growth plans, expected capital requirements
and other conditions existing at such future time including, without limitation, contractual restrictions (including covenants contained
in the agreements governing any indebtedness that the Corporation has incurred or may incur in the future, including the terms of the
Credit Facilities) and satisfaction of the solvency tests imposed on the Corporation under applicable corporate law. There can be no assurance
of the number of Common Shares that the Corporation will acquire pursuant to a share buyback, if any, in the future.
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 and any
special dividends) 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.
38 | Baytex Energy Corp. Second Quarter Report 2024 | |
Baytex Energy Corp.
Condensed Consolidated Interim Statements of Financial Position
(thousands of Canadian dollars) (unaudited)
| |
| | |
As at | |
| |
Notes | | |
June 30, 2024 | | |
December 31, 2023 | |
ASSETS | |
| | | |
| | | |
| | |
Current assets | |
| | | |
| | | |
| | |
Cash | |
| | | |
$ | 35,887 | | |
$ | 55,815 | |
Trade receivables | |
| 13, 17 | | |
| 429,098 | | |
| 339,405 | |
Prepaids and other assets | |
| 14 | | |
| 22,938 | | |
| 21,530 | |
Financial derivatives | |
| 17 | | |
| 7,028 | | |
| 23,274 | |
| |
| | | |
| 494,951 | | |
| 440,024 | |
Non-current assets | |
| | | |
| | | |
| | |
Exploration and evaluation assets | |
| 5 | | |
| 122,214 | | |
| 90,919 | |
Oil and gas properties | |
| 6 | | |
| 6,862,101 | | |
| 6,619,033 | |
Other plant and equipment | |
| | | |
| 9,223 | | |
| 7,936 | |
Lease assets | |
| | | |
| 24,237 | | |
| 28,145 | |
Prepaids and other assets | |
| 14 | | |
| 58,867 | | |
| 61,729 | |
Deferred income tax asset | |
| 14 | | |
| 199,333 | | |
| 213,145 | |
| |
| | | |
$ | 7,770,926 | | |
$ | 7,460,931 | |
LIABILITIES | |
| | | |
| | | |
| | |
Current liabilities | |
| | | |
| | | |
| | |
Trade payables | |
| 17 | | |
$ | 617,222 | | |
$ | 477,295 | |
Financial derivatives | |
| 17 | | |
| 5,314 | | |
| — | |
Share-based compensation liability | |
| 11 | | |
| 18,312 | | |
| 28,508 | |
Dividends payable | |
| 10, 17 | | |
| 18,161 | | |
| 18,381 | |
Lease obligations | |
| | | |
| 8,471 | | |
| 13,391 | |
Asset retirement obligations | |
| 9 | | |
| 19,439 | | |
| 20,448 | |
| |
| | | |
| 686,919 | | |
| 558,023 | |
Non-current liabilities | |
| | | |
| | | |
| | |
Other long-term liabilities | |
| | | |
| 19,845 | | |
| 19,147 | |
Share-based compensation liability | |
| 11 | | |
| 4,394 | | |
| 7,224 | |
Credit facilities | |
| 7 | | |
| 607,589 | | |
| 848,749 | |
Long-term notes | |
| 8 | | |
| 1,833,182 | | |
| 1,562,361 | |
Lease obligations | |
| | | |
| 18,001 | | |
| 16,056 | |
Asset retirement obligations | |
| 9 | | |
| 603,586 | | |
| 602,951 | |
Deferred income tax liability | |
| 14 | | |
| 39,269 | | |
| 21,333 | |
| |
| | | |
| 3,812,785 | | |
| 3,635,844 | |
SHAREHOLDERS’ EQUITY | |
| | | |
| | | |
| | |
Shareholders' capital | |
| 10 | | |
| 6,391,108 | | |
| 6,527,289 | |
Contributed surplus | |
| | | |
| 246,530 | | |
| 193,077 | |
Accumulated other comprehensive income | |
| | | |
| 853,499 | | |
| 690,917 | |
Deficit | |
| | | |
| (3,532,996 | ) | |
| (3,586,196 | ) |
| |
| | | |
| 3,958,141 | | |
| 3,825,087 | |
| |
| | | |
$ | 7,770,926 | | |
$ | 7,460,931 | |
Subsequent events (notes 10 and 17)
See accompanying notes to the condensed consolidated interim financial
statements.
| Baytex Energy Corp. Second Quarter Report 2024 | 39 |
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 | | |
2024 | | |
2023 | | |
2024 | | |
2023 | |
Revenue, net of royalties | |
| | | |
| | | |
| | | |
| | | |
| | |
Petroleum and natural gas sales | |
| 13 | | |
$ | 1,133,123 | | |
$ | 598,760 | | |
$ | 2,117,315 | | |
$ | 1,154,096 | |
Royalties | |
| | | |
| (240,440 | ) | |
| (107,920 | ) | |
| (449,611 | ) | |
| (201,173 | ) |
| |
| | | |
| 892,683 | | |
| 490,840 | | |
| 1,667,704 | | |
| 952,923 | |
| |
| | | |
| | | |
| | | |
| | | |
| | |
Expenses | |
| | | |
| | | |
| | | |
| | | |
| | |
Operating | |
| | | |
| 167,705 | | |
| 119,438 | | |
| 341,140 | | |
| 231,846 | |
Transportation | |
| | | |
| 33,314 | | |
| 14,574 | | |
| 63,149 | | |
| 31,579 | |
Blending and other | |
| | | |
| 67,685 | | |
| 52,995 | | |
| 131,893 | | |
| 112,676 | |
General and administrative | |
| | | |
| 21,006 | | |
| 15,240 | | |
| 43,418 | | |
| 26,974 | |
Transaction costs | |
| | | |
| — | | |
| 32,832 | | |
| 1,539 | | |
| 41,703 | |
Exploration and evaluation | |
| 5 | | |
| 649 | | |
| 369 | | |
| 667 | | |
| 532 | |
Depletion and depreciation | |
| | | |
| 353,101 | | |
| 176,144 | | |
| 697,238 | | |
| 342,143 | |
Share-based compensation | |
| 11 | | |
| 5,565 | | |
| 16,918 | | |
| 15,088 | | |
| 26,741 | |
Financing and interest | |
| 15 | | |
| 91,617 | | |
| 34,497 | | |
| 152,884 | | |
| 58,222 | |
Financial derivatives (gain) loss | |
| 17 | | |
| (8,533 | ) | |
| 3,038 | | |
| 18,329 | | |
| (11,587 | ) |
Foreign exchange loss (gain) | |
| 16 | | |
| 20,055 | | |
| (11,939 | ) | |
| 59,992 | | |
| (12,002 | ) |
Loss on dispositions and property swaps | |
| | | |
| 6,311 | | |
| — | | |
| 3,650 | | |
| 336 | |
Other expense (income) | |
| | | |
| 1,025 | | |
| 141 | | |
| 2,096 | | |
| (917 | ) |
| |
| | | |
| 759,500 | | |
| 454,247 | | |
| 1,531,083 | | |
| 848,246 | |
Net income before income taxes | |
| | | |
| 133,183 | | |
| 36,593 | | |
| 136,621 | | |
| 104,677 | |
Income tax expense (recovery) | |
| 14 | | |
| | | |
| | | |
| | | |
| | |
Current income tax expense | |
| | | |
| 6,475 | | |
| 1,350 | | |
| 8,155 | | |
| 2,470 | |
Deferred income tax expense (recovery) | |
| | | |
| 22,810 | | |
| (178,360 | ) | |
| 38,611 | | |
| (162,837 | ) |
| |
| | | |
| 29,285 | | |
| (177,010 | ) | |
| 46,766 | | |
| (160,367 | ) |
Net income | |
| | | |
$ | 103,898 | | |
$ | 213,603 | | |
$ | 89,855 | | |
$ | 265,044 | |
Other comprehensive income (loss) | |
| | | |
| | | |
| | | |
| | | |
| | |
Foreign currency translation adjustment | |
| | | |
| 52,019 | | |
| (46,457 | ) | |
| 162,582 | | |
| (47,005 | ) |
Comprehensive income | |
| | | |
$ | 155,917 | | |
$ | 167,146 | | |
$ | 252,437 | | |
$ | 218,039 | |
| |
| | | |
| | | |
| | | |
| | | |
| | |
Net income per common share | |
| 12 | | |
| | | |
| | | |
| | | |
| | |
Basic | |
| | | |
$ | 0.13 | | |
$ | 0.37 | | |
$ | 0.11 | | |
$ | 0.47 | |
Diluted | |
| | | |
$ | 0.13 | | |
$ | 0.36 | | |
$ | 0.11 | | |
$ | 0.47 | |
| |
| | | |
| | | |
| | | |
| | | |
| | |
Weighted average common shares (000's) | |
| 12 | | |
| | | |
| | | |
| | | |
| | |
Basic | |
| | | |
| 814,151 | | |
| 583,365 | | |
| 817,931 | | |
| 564,319 | |
Diluted | |
| | | |
| 818,025 | | |
| 588,170 | | |
| 821,290 | | |
| 569,284 | |
See accompanying notes to the condensed consolidated interim financial
statements.
40 | Baytex Energy Corp. Second Quarter Report 2024 | |
Baytex Energy Corp.
Condensed Consolidated Interim Statements of Changes in Equity
(thousands of Canadian dollars) (unaudited)
| |
Notes | |
Shareholders’ capital | | |
Contributed
surplus | | |
Accumulated
other
comprehensive
income | | |
Deficit | | |
Total equity | |
Balance at December 31, 2022 | |
| |
$ | 5,499,664 | | |
$ | 89,879 | | |
$ | 756,195 | | |
$ | (3,315,321 | ) | |
$ | 3,030,417 | |
Issued on corporate acquisition | |
| |
| 1,326,435 | | |
| 21,316 | | |
| — | | |
| — | | |
| 1,347,751 | |
Vesting of share awards | |
| |
| 26,229 | | |
| (37,462 | ) | |
| — | | |
| — | | |
| (11,233 | ) |
Share-based compensation | |
| |
| — | | |
| 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 | |
| |
| |
| | | |
| | | |
| | | |
| | | |
| | |
Balance at December 31, 2023 | |
| |
$ | 6,527,289 | | |
$ | 193,077 | | |
$ | 690,917 | | |
$ | (3,586,196 | ) | |
$ | 3,825,087 | |
Vesting of share awards | |
10 | |
| 1,167 | | |
| — | | |
| — | | |
| — | | |
| 1,167 | |
Repurchase of common shares for cancellation | |
10 | |
| (137,348 | ) | |
| 53,453 | | |
| — | | |
| — | | |
| (83,895 | ) |
Dividends declared | |
10 | |
| — | | |
| — | | |
| — | | |
| (36,655 | ) | |
| (36,655 | ) |
Comprehensive income | |
| |
| — | | |
| — | | |
| 162,582 | | |
| 89,855 | | |
| 252,437 | |
Balance at June 30, 2024 | |
| |
$ | 6,391,108 | | |
$ | 246,530 | | |
$ | 853,499 | | |
$ | (3,532,996 | ) | |
$ | 3,958,141 | |
See accompanying notes to the condensed consolidated interim financial
statements.
| Baytex Energy Corp. Second Quarter Report 2024 | 41 |
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 | | |
2024 | | |
2023 | | |
2024 | | |
2023 | |
CASH PROVIDED BY (USED IN): | |
| | |
| | | |
| | | |
| | | |
| | |
Operating activities | |
| | |
| | | |
| | | |
| | | |
| | |
Net income | |
| | |
$ | 103,898 | | |
$ | 213,603 | | |
$ | 89,855 | | |
$ | 265,044 | |
Adjustments for: | |
| | |
| | | |
| | | |
| | | |
| | |
Non-cash share-based compensation | |
11 | | |
| — | | |
| 16,237 | | |
| — | | |
| 16,237 | |
Unrealized foreign exchange loss (gain) | |
16 | | |
| 19,189 | | |
| (12,880 | ) | |
| 57,907 | | |
| (13,093 | ) |
Exploration and evaluation | |
5 | | |
| 649 | | |
| 369 | | |
| 667 | | |
| 532 | |
Depletion and depreciation | |
| | |
| 353,101 | | |
| 176,144 | | |
| 697,238 | | |
| 342,143 | |
Non-cash financing and interest | |
15 | | |
| 37,671 | | |
| 6,242 | | |
| 45,658 | | |
| 11,592 | |
Non-cash other income | |
9 | | |
| — | | |
| — | | |
| — | | |
| (1,271 | ) |
Unrealized financial derivatives (gain) loss | |
17 | | |
| (10,790 | ) | |
| 19,403 | | |
| 21,560 | | |
| 10,193 | |
Cash premiums on derivatives | |
| | |
| — | | |
| (2,263 | ) | |
| — | | |
| (2,263 | ) |
Loss on dispositions and property swaps | |
| | |
| 6,311 | | |
| — | | |
| 3,650 | | |
| 336 | |
Deferred income tax expense (recovery) | |
14 | | |
| 22,810 | | |
| (178,360 | ) | |
| 38,611 | | |
| (162,837 | ) |
Asset retirement obligations settled | |
9 | | |
| (7,115 | ) | |
| (5,392 | ) | |
| (13,626 | ) | |
| (9,518 | ) |
Change in non-cash working capital | |
| | |
| (20,140 | ) | |
| (40,795 | ) | |
| (52,163 | ) | |
| (79,849 | ) |
Cash flows from operating activities | |
| | |
| 505,584 | | |
| 192,308 | | |
| 889,357 | | |
| 377,246 | |
| |
| | |
| | | |
| | | |
| | | |
| | |
Financing activities | |
| | |
| | | |
| | | |
| | | |
| | |
(Decrease) increase in credit facilities | |
| | |
| (225,961 | ) | |
| 577,428 | | |
| (247,516 | ) | |
| 601,979 | |
Decrease in acquired credit facilities | |
3 | | |
| — | | |
| (373,608 | ) | |
| — | | |
| (373,608 | ) |
Debt issuance costs | |
| | |
| (25,023 | ) | |
| (39,925 | ) | |
| (25,023 | ) | |
| (39,925 | ) |
Payments on lease obligations | |
| | |
| (5,478 | ) | |
| (1,181 | ) | |
| (10,350 | ) | |
| (2,336 | ) |
Net proceeds from issuance of long-term notes | |
8 | | |
| 780,936 | | |
| 1,046,197 | | |
| 780,936 | | |
| 1,046,197 | |
Redemption of long-term notes | |
8 | | |
| (580,913 | ) | |
| — | | |
| (580,913 | ) | |
| — | |
Redemption of acquired long-term notes | |
3 | | |
| — | | |
| (569,256 | ) | |
| — | | |
| (569,256 | ) |
Repurchase of common shares | |
10 | | |
| (80,890 | ) | |
| — | | |
| (83,895 | ) | |
| — | |
Dividends declared | |
10 | | |
| (18,161 | ) | |
| — | | |
| (36,655 | ) | |
| — | |
Change in non-cash working capital | |
| | |
| (4,105 | ) | |
| — | | |
| (2,100 | ) | |
| — | |
Cash flows (used in) from financing activities | |
| | |
| (159,595 | ) | |
| 639,655 | | |
| (205,516 | ) | |
| 663,051 | |
| |
| | |
| | | |
| | | |
| | | |
| | |
Investing activities | |
| | |
| | | |
| | | |
| | | |
| | |
Additions to exploration and evaluation assets | |
5 | | |
| — | | |
| (741 | ) | |
| — | | |
| (1,231 | ) |
Additions to oil and gas properties | |
6 | | |
| (339,573 | ) | |
| (169,963 | ) | |
| (752,124 | ) | |
| (403,099 | ) |
Additions to other plant and equipment | |
| | |
| (1,279 | ) | |
| (580 | ) | |
| (3,536 | ) | |
| (1,021 | ) |
Corporate acquisition, net of cash acquired | |
3 | | |
| — | | |
| (662,579 | ) | |
| — | | |
| (662,579 | ) |
Property acquisitions | |
| | |
| (3,349 | ) | |
| 62 | | |
| (38,752 | ) | |
| (444 | ) |
Proceeds from dispositions | |
| | |
| 2,695 | | |
| 50 | | |
| 2,720 | | |
| 285 | |
Change in non-cash working capital | |
| | |
| 2,264 | | |
| 14,980 | | |
| 87,923 | | |
| 41,965 | |
Cash flows used in investing activities | |
| | |
| (339,242 | ) | |
| (818,771 | ) | |
| (703,769 | ) | |
| (1,026,124 | ) |
| |
| | |
| | | |
| | | |
| | | |
| | |
Change in cash | |
| | |
| 6,747 | | |
| 13,192 | | |
| (19,928 | ) | |
| 14,173 | |
Cash, beginning of period | |
| | |
| 29,140 | | |
| 6,445 | | |
| 55,815 | | |
| 5,464 | |
Cash, end of period | |
| | |
$ | 35,887 | | |
$ | 19,637 | | |
$ | 35,887 | | |
$ | 19,637 | |
| |
| | |
| | | |
| | | |
| | | |
| | |
Supplementary information | |
| | |
| | | |
| | | |
| | | |
| | |
Interest paid | |
| | |
$ | 86,727 | | |
$ | 7,535 | | |
$ | 105,016 | | |
$ | 38,004 | |
Income taxes paid | |
| | |
$ | 11,877 | | |
$ | 3,603 | | |
$ | 16,421 | | |
$ | 3,603 | |
See accompanying notes to the condensed consolidated interim financial
statements.
42 | Baytex Energy Corp. Second Quarter Report 2024 | |
Baytex Energy Corp.
Notes to the Condensed Consolidated Interim Financial Statements
For the periods ended June 30, 2024 and 2023
(all tabular amounts in thousands of Canadian dollars, except per
common share amounts) (unaudited)
Baytex Energy Corp. (the “Company”
or “Baytex”) is an energy company engaged in the acquisition, development and production of oil and natural gas in the Western
Canadian Sedimentary Basin and in Texas, United States. The Company’s common shares are traded on the Toronto Stock Exchange and
the New York Stock Exchange under the symbol BTE. The Company’s head and principal office is located at 2800, 520 – 3rd Avenue
S.W., Calgary, Alberta, T2P 0R3, and its registered office is located at 2400, 525 – 8th Avenue S.W., Calgary, Alberta, T2P 1G1.
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 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,
2023 ("2023 annual consolidated financial statements").
The consolidated financial statements were approved by the Board of
Directors of Baytex on July 25, 2024.
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 2023 annual consolidated financial
statements of the Company are available through its filings on SEDAR+ at www.sedarplus.ca and through the U.S. Securities and Exchange
Commission at www.sec.gov.
Estimation Uncertainty
Management makes judgments 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.
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 ("ISSB") has issued an IFRS Sustainability Disclosure Standard with the objective to develop a global framework for environmental
sustainability disclosure. The Canadian Sustainability Standards Board has released proposed standards that are aligned with the ISSB
release and include suggestions for Canadian-specific modifications. 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.
Material Accounting Policies
Except as described below, the accounting policies,
critical accounting judgments and significant estimates used in these consolidated financial statements are consistent with those used
in the preparation of the 2023 annual consolidated financial statements.
New Accounting Standards Adopted
Effective January 1, 2024, Baytex adopted
amendments to IAS 1 Presentation of Financial Statements which was issued by the IASB in January 2020. The amendments further
clarify the requirements for the presentation of liabilities as current or non-current in the consolidated statements of financial position.
These amendments have not had a material impact on our consolidated
financial statements.
| Baytex Energy Corp. Second Quarter Report 2024 | 43 |
On June 20, 2023, Baytex closed the acquisition
of Ranger Oil Corporation (“Ranger”), a publicly traded oil and gas exploration and production company with operations in
the Eagle Ford. Baytex acquired all of the issued and outstanding common shares of Ranger and is treated as the acquirer for accounting
purposes. The acquisition increases Baytex's Eagle Ford scale and provides an operating platform to effectively allocate capital across
the Western Canadian Sedimentary Basin and the Eagle Ford.
The acquisition was accounted for as a business
combination with the net assets and liabilities recorded at fair value at the acquisition date. The total consideration of US$1.6 billion
($2.1 billion) consisted of $732.8 million of cash consideration and 311.4 million Baytex common shares valued at approximately $1.3
billion (based on the closing price of Baytex’s common shares of $4.26 per share on the Toronto Stock Exchange on June 20,
2023). Under the terms of the agreement, Ranger shareholders received 7.49 Baytex shares plus US$13.31 cash for each share of Ranger
common stock.
The fair value of oil and gas properties acquired
was primarily based on estimated cash flows associated with proved and probable oil and gas reserves acquired and the discount rate.
Factors that impact these reserves cash flows include forecasted production volumes, royalty obligations, operating and capital costs,
taxes and commodity prices. The estimation of reserves cash flows involves the expertise of the independent qualified reserve evaluators.
Any changes to these estimates and assumptions could impact the calculation of the recoverable amount and the carrying value of assets.
The fair value of the acquired oil and gas properties were determined using a discount rate of 12.2%.
Asset retirement obligations were determined
using internal estimates of the timing and estimated costs associated with the abandonment and reclamation of the wells and facilities
acquired using a market rate of interest of 9.0%.
The total consideration paid and estimates of
the fair value of the assets and liabilities acquired as at the date of the acquisition are set forth in the table below. The purchase
price equation was based on management's best estimate of the assets acquired and liabilities assumed. There were no measurement period
adjustments recorded during the three and six months ended June 30, 2024 and the purchase price is considered final.
| |
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 | |
$ | 2,337,173 | | |
$ | 3,096,404 | |
Working capital deficiency excluding bank debt and financial
derivatives (3) | |
| (120,565 | ) | |
| (159,731 | ) |
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 | |
| 76,123 | | |
| 100,852 | |
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) | Following closing of the transaction,
holders of awards outstanding under Ranger's share based compensation plans are entitled
to Baytex common shares rather than Ranger common shares with adjustment to the quantity
outstanding based on the exchange ratio for Ranger shares. The fair value of share awards
allocated to consideration was based on the service period that had occurred prior to the
acquisition date while the remaining fair value of the share awards assumed by Baytex will
be recognized over the remaining future service periods (note 11). Included in this balance
is $21.3 million (US$16.1 million) of awards that were fully vested at close of the Ranger
acquisition and $5.3 million (US$4.0 million) of cash-based awards included in share-based
compensation liability. |
(3) | Includes $70.3 million (US$53.0
million) of cash. Trade receivables acquired is net of a provision for expected credit losses
of approximately $0.3 million. |
44 | Baytex Energy Corp. Second Quarter Report 2024 | |
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 | |
2024 | | |
2023 | | |
2024 | | |
2023 | | |
2024 | | |
2023 | | |
2024 | | |
2023 | |
Revenue, net of royalties | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Petroleum and natural
gas sales | |
$ | 508,560 | | |
$ | 390,292 | | |
$ | 624,563 | | |
$ | 208,468 | | |
$ | — | | |
$ | — | | |
$ | 1,133,123 | | |
$ | 598,760 | |
Royalties | |
| (72,894 | ) | |
| (47,309 | ) | |
| (167,546 | ) | |
| (60,611 | ) | |
| — | | |
| — | | |
| (240,440 | ) | |
| (107,920 | ) |
| |
| 435,666 | | |
| 342,983 | | |
| 457,017 | | |
| 147,857 | | |
| — | | |
| — | | |
| 892,683 | | |
| 490,840 | |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Expenses | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Operating | |
| 84,415 | | |
| 91,354 | | |
| 83,290 | | |
| 28,084 | | |
| — | | |
| — | | |
| 167,705 | | |
| 119,438 | |
Transportation | |
| 19,569 | | |
| 13,240 | | |
| 13,745 | | |
| 1,334 | | |
| — | | |
| — | | |
| 33,314 | | |
| 14,574 | |
Blending and other | |
| 67,685 | | |
| 52,995 | | |
| — | | |
| — | | |
| — | | |
| — | | |
| 67,685 | | |
| 52,995 | |
General and administrative | |
| — | | |
| — | | |
| — | | |
| — | | |
| 21,006 | | |
| 15,240 | | |
| 21,006 | | |
| 15,240 | |
Transaction costs | |
| — | | |
| — | | |
| — | | |
| — | | |
| — | | |
| 32,832 | | |
| — | | |
| 32,832 | |
Exploration and evaluation | |
| 649 | | |
| 369 | | |
| — | | |
| — | | |
| — | | |
| — | | |
| 649 | | |
| 369 | |
Depletion and depreciation | |
| 117,865 | | |
| 112,262 | | |
| 231,853 | | |
| 62,211 | | |
| 3,383 | | |
| 1,671 | | |
| 353,101 | | |
| 176,144 | |
Share-based compensation | |
| — | | |
| — | | |
| — | | |
| — | | |
| 5,565 | | |
| 16,918 | | |
| 5,565 | | |
| 16,918 | |
Financing and interest | |
| — | | |
| — | | |
| — | | |
| — | | |
| 91,617 | | |
| 34,497 | | |
| 91,617 | | |
| 34,497 | |
Financial derivatives (gain)
loss | |
| — | | |
| — | | |
| — | | |
| — | | |
| (8,533 | ) | |
| 3,038 | | |
| (8,533 | ) | |
| 3,038 | |
Foreign exchange loss (gain) | |
| — | | |
| — | | |
| — | | |
| — | | |
| 20,055 | | |
| (11,939 | ) | |
| 20,055 | | |
| (11,939 | ) |
Loss on dispositions and property
swaps | |
| 1,356 | | |
| — | | |
| 4,955 | | |
| — | | |
| — | | |
| — | | |
| 6,311 | | |
| — | |
Other expense | |
| — | | |
| — | | |
| — | | |
| — | | |
| 1,025 | | |
| 141 | | |
| 1,025 | | |
| 141 | |
| |
| 291,539 | | |
| 270,220 | | |
| 333,843 | | |
| 91,629 | | |
| 134,118 | | |
| 92,398 | | |
| 759,500 | | |
| 454,247 | |
Net
income (loss) before income taxes | |
| 144,127 | | |
| 72,763 | | |
| 123,174 | | |
| 56,228 | | |
| (134,118 | ) | |
| (92,398 | ) | |
| 133,183 | | |
| 36,593 | |
Income tax expense (recovery) | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Current income tax expense | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| 6,475 | | |
| 1,350 | |
Deferred
income tax expense (recovery) | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| 22,810 | | |
| (178,360 | ) |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| 29,285 | | |
| (177,010 | ) |
Net
income (loss) | |
$ | 144,127 | | |
$ | 72,763 | | |
$ | 123,174 | | |
$ | 56,228 | | |
$ | (134,118 | ) | |
$ | (92,398 | ) | |
$ | 103,898 | | |
$ | 213,603 | |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Additions to exploration and
evaluation assets | |
| — | | |
| 741 | | |
| — | | |
| — | | |
| — | | |
| — | | |
| — | | |
| 741 | |
Additions to oil and gas properties | |
| 101,916 | | |
| 95,662 | | |
| 237,657 | | |
| 74,301 | | |
| — | | |
| — | | |
| 339,573 | | |
| 169,963 | |
Corporate acquisition, net of
cash acquired | |
| — | | |
| — | | |
| — | | |
| 662,439 | | |
| — | | |
| — | | |
| — | | |
| 662,439 | |
Property acquisitions | |
| 1,802 | | |
| (62 | ) | |
| 1,547 | | |
| — | | |
| — | | |
| — | | |
| 3,349 | | |
| (62 | ) |
Proceeds
from dispositions | |
| 157 | | |
| (50 | ) | |
| (2,852 | ) | |
| — | | |
| — | | |
| — | | |
| (2,695 | ) | |
| (50 | ) |
| Baytex Energy Corp. Second Quarter Report 2024 | 45 |
| |
Canada | | |
U.S. | | |
Corporate | | |
Consolidated | |
Six
Months Ended June 30 | |
2024 | | |
2023 | | |
2024 | | |
2023 | | |
2024 | | |
2023 | | |
2024 | | |
2023 | |
Revenue, net of royalties | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| |
Petroleum and natural
gas sales | |
$ | 924,873 | | |
$ | 775,914 | | |
$ | 1,192,442 | | |
$ | 378,182 | | |
$ | — | | |
$ | — | | |
$ | 2,117,315 | | |
$ | 1,154,096 | |
Royalties | |
| (129,458 | ) | |
| (91,164 | ) | |
| (320,153 | ) | |
| (110,009 | ) | |
| — | | |
| — | | |
| (449,611 | ) | |
| (201,173 | ) |
| |
| 795,415 | | |
| 684,750 | | |
| 872,289 | | |
| 268,173 | | |
| — | | |
| — | | |
| 1,667,704 | | |
| 952,923 | |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Expenses | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Operating | |
| 169,818 | | |
| 182,534 | | |
| 171,322 | | |
| 49,312 | | |
| — | | |
| — | | |
| 341,140 | | |
| 231,846 | |
Transportation | |
| 37,779 | | |
| 30,245 | | |
| 25,370 | | |
| 1,334 | | |
| — | | |
| — | | |
| 63,149 | | |
| 31,579 | |
Blending and other | |
| 131,893 | | |
| 112,676 | | |
| — | | |
| — | | |
| — | | |
| — | | |
| 131,893 | | |
| 112,676 | |
General and administrative | |
| — | | |
| — | | |
| — | | |
| — | | |
| 43,418 | | |
| 26,974 | | |
| 43,418 | | |
| 26,974 | |
Transaction costs | |
| — | | |
| — | | |
| — | | |
| — | | |
| 1,539 | | |
| 41,703 | | |
| 1,539 | | |
| 41,703 | |
Exploration and evaluation | |
| 667 | | |
| 532 | | |
| — | | |
| — | | |
| — | | |
| — | | |
| 667 | | |
| 532 | |
Depletion and depreciation | |
| 234,861 | | |
| 231,733 | | |
| 456,292 | | |
| 107,175 | | |
| 6,085 | | |
| 3,235 | | |
| 697,238 | | |
| 342,143 | |
Share-based compensation | |
| — | | |
| — | | |
| — | | |
| — | | |
| 15,088 | | |
| 26,741 | | |
| 15,088 | | |
| 26,741 | |
Financing and interest | |
| — | | |
| — | | |
| — | | |
| — | | |
| 152,884 | | |
| 58,222 | | |
| 152,884 | | |
| 58,222 | |
Financial derivatives loss (gain) | |
| — | | |
| — | | |
| — | | |
| — | | |
| 18,329 | | |
| (11,587 | ) | |
| 18,329 | | |
| (11,587 | ) |
Foreign exchange loss (gain) | |
| — | | |
| — | | |
| — | | |
| — | | |
| 59,992 | | |
| (12,002 | ) | |
| 59,992 | | |
| (12,002 | ) |
(Gain) loss on dispositions and
property swaps | |
| (1,055 | ) | |
| 336 | | |
| 4,705 | | |
| — | | |
| — | | |
| — | | |
| 3,650 | | |
| 336 | |
Other expense
(income) | |
| — | | |
| (1,271 | ) | |
| — | | |
| — | | |
| 2,096 | | |
| 354 | | |
| 2,096 | | |
| (917 | ) |
| |
| 573,963 | | |
| 556,785 | | |
| 657,689 | | |
| 157,821 | | |
| 299,431 | | |
| 133,640 | | |
| 1,531,083 | | |
| 848,246 | |
Net
income (loss) before income taxes | |
| 221,452 | | |
| 127,965 | | |
| 214,600 | | |
| 110,352 | | |
| (299,431 | ) | |
| (133,640 | ) | |
| 136,621 | | |
| 104,677 | |
Income tax expense (recovery) | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Current income tax expense | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| 8,155 | | |
| 2,470 | |
Deferred
income tax expense (recovery) | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| 38,611 | | |
| (162,837 | ) |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| 46,766 | | |
| (160,367 | ) |
Net
income (loss) | |
$ | 221,452 | | |
$ | 127,965 | | |
$ | 214,600 | | |
$ | 110,352 | | |
$ | (299,431 | ) | |
$ | (133,640 | ) | |
$ | 89,855 | | |
$ | 265,044 | |
| |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
Additions to exploration and
evaluation assets | |
| — | | |
| 1,231 | | |
| — | | |
| — | | |
| — | | |
| — | | |
| — | | |
| 1,231 | |
Additions to oil and gas properties | |
| 260,042 | | |
| 279,778 | | |
| 492,082 | | |
| 123,321 | | |
| — | | |
| — | | |
| 752,124 | | |
| 403,099 | |
Corporate acquisition, net of
cash acquired | |
| — | | |
| — | | |
| — | | |
| 662,439 | | |
| — | | |
| — | | |
| — | | |
| 662,439 | |
Property acquisitions | |
| 36,077 | | |
| 444 | | |
| 2,675 | | |
| — | | |
| — | | |
| — | | |
| 38,752 | | |
| 444 | |
Proceeds
from dispositions | |
| 132 | | |
| (285 | ) | |
| (2,852 | ) | |
| — | | |
| — | | |
| — | | |
| (2,720 | ) | |
| (285 | ) |
| |
June 30, 2024 | | |
December 31, 2023 | |
Canadian assets | |
$ | 2,415,720 | | |
$ | 2,289,083 | |
U.S. assets | |
| 5,314,718 | | |
| 5,112,493 | |
Corporate assets | |
| 40,488 | | |
| 59,355 | |
Total consolidated assets | |
$ | 7,770,926 | | |
$ | 7,460,931 | |
46 | Baytex Energy Corp. Second Quarter Report 2024 | |
| 5. | EXPLORATION AND EVALUATION ASSETS |
| |
June 30, 2024 | | |
December 31, 2023 | |
Balance, beginning of period | |
$ | 90,919 | | |
$ | 168,684 | |
Property acquisitions | |
| 35,467 | | |
| 18,486 | |
Divestitures | |
| (1,173 | ) | |
| (2,965 | ) |
Property swaps | |
| (68 | ) | |
| 1,000 | |
Exploration and evaluation expense | |
| (667 | ) | |
| (8,896 | ) |
Transfer to oil and gas properties (note 6) | |
| (2,264 | ) | |
| (83,530 | ) |
Foreign currency translation | |
| — | | |
| (1,860 | ) |
Balance, end of period | |
$ | 122,214 | | |
$ | 90,919 | |
At June 30, 2024 and December 31, 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").
| |
Cost | | |
Accumulated
depletion | | |
Net book value | |
Balance, December 31, 2022 | |
$ | 12,042,216 | | |
$ | (7,421,450 | ) | |
$ | 4,620,766 | |
Capital expenditures | |
| 1,012,787 | | |
| — | | |
| 1,012,787 | |
Corporate acquisition (note 3) | |
| 3,096,404 | | |
| — | | |
| 3,096,404 | |
Property acquisitions | |
| 20,263 | | |
| — | | |
| 20,263 | |
Transfers from exploration and evaluation assets (note 5) | |
| 83,530 | | |
| — | | |
| 83,530 | |
Transfers from lease assets | |
| 7,611 | | |
| — | | |
| 7,611 | |
Change in asset retirement obligations (note 9) | |
| 54,166 | | |
| — | | |
| 54,166 | |
Divestitures | |
| (660,920 | ) | |
| 317,651 | | |
| (343,269 | ) |
Property swaps | |
| (2,975 | ) | |
| 3,756 | | |
| 781 | |
Impairment loss | |
| — | | |
| (833,662 | ) | |
| (833,662 | ) |
Foreign currency translation | |
| (127,065 | ) | |
| 66,501 | | |
| (60,564 | ) |
Depletion | |
| — | | |
| (1,039,780 | ) | |
| (1,039,780 | ) |
Balance, December 31, 2023 | |
$ | 15,526,017 | | |
$ | (8,906,984 | ) | |
$ | 6,619,033 | |
Capital expenditures | |
| 752,124 | | |
| — | | |
| 752,124 | |
Property acquisitions | |
| 3,334 | | |
| — | | |
| 3,334 | |
Transfers from exploration and evaluation assets (note 5) | |
| 2,264 | | |
| — | | |
| 2,264 | |
Transfers from lease assets | |
| 7,418 | | |
| — | | |
| 7,418 | |
Change in asset retirement obligations (note 9) | |
| 1,291 | | |
| — | | |
| 1,291 | |
Divestitures | |
| (2,626 | ) | |
| 469 | | |
| (2,157 | ) |
Property swaps | |
| 997 | | |
| 682 | | |
| 1,679 | |
Foreign currency translation | |
| 305,550 | | |
| (137,282 | ) | |
| 168,268 | |
Depletion | |
| — | | |
| (691,153 | ) | |
| (691,153 | ) |
Balance, June 30, 2024 | |
$ | 16,596,369 | | |
$ | (9,734,268 | ) | |
$ | 6,862,101 | |
At June 30, 2024, there were no indicators
of impairment or impairment reversal for oil and gas properties in any of the Company's CGUs.
At December 31, 2023, the Company identified
indicators of impairment for oil and gas properties in the legacy non-operated Eagle Ford CGU due to changes in reserves and in the Viking
CGU due to changes in reserves and a loss recorded on disposition of an asset. The recoverable amounts for the two CGUs were not sufficient
to support their carrying values which resulted in an impairment loss of $833.7 million recorded at December 31, 2023. The recoverable
amount for each CGU is based on estimated cash flows associated with proved and probable oil and gas reserves from an independent reserve
report prepared as at December 31, 2023 utilizing a discount rate based on Baytex's corporate weighted average cost of capital adjusted
for asset specific factors. The after-tax discount rates applied to the cash flows were between 12% and 14%.
| Baytex Energy Corp. Second Quarter Report 2024 | 47 |
| |
June 30, 2024 | | |
December 31, 2023 | |
Credit facilities - U.S. dollar denominated (1) | |
$ | 244,305 | | |
$ | 311,980 | |
Credit facilities - Canadian dollar denominated | |
| 381,671 | | |
| 552,756 | |
Credit facilities - principal (2) | |
| 625,976 | | |
| 864,736 | |
Unamortized debt issuance costs | |
| (18,387 | ) | |
| (15,987 | ) |
Credit facilities | |
$ | 607,589 | | |
$ | 848,749 | |
| (1) | U.S. dollar denominated credit facilities balance was US$178.5 million as at June 30, 2024 (December 31, 2023 - US$236.3
million). |
| (2) | The decrease in the principal amount of the credit facilities outstanding from December 31, 2023
to June 30, 2024 is the result of net repayments of $247.5 million, partially offset by an increase in the reported amount of U.S.
denominated debt of $8.8 million due to foreign exchange. |
On May 9, 2024, Baytex extended the maturity
of the revolving credit facilities (the "Credit Facilities") from April 1, 2026 to May 9, 2028. There are no changes
to the loan balances or financial covenants as a result of the amendment. Following the amendment, borrowing in Canadian funds previously
based on the banker's acceptance rate has been replaced with borrowings based on the Canadian Overnight Repo Rate Average ("CORRA").
At June 30, 2024, Baytex had US$1.1 billion
($1.5 billion) of revolving credit facilities that mature on May 9, 2028. The Credit Facilities are secured and are comprised of
a US$50 million operating loan and a US$750 million syndicated revolving loan for Baytex and a US$45 million operating loan and a US$255
million syndicated revolving loan for Baytex's wholly-owned subsidiary, Baytex Energy USA, Inc.
The 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, CORRA rates or secured overnight financing rates ("SOFR"),
plus applicable margins.
The weighted average interest rate on the Credit
Facilities was 8.0% for the six months ended June 30, 2024 (6.5% for six months ended June 30, 2023).
The following table summarizes the financial covenants
applicable to the Credit Facilities and our compliance therewith at June 30, 2024.
Covenant Description | |
| Position as at June 30, 2024 | | |
| Covenant | |
Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio) | |
| 0.3:1.0 | | |
| 3.5:1.0 | |
Interest Coverage (3) (Minimum Ratio) | |
| 10.3:1.0 | | |
| 3.5:1.0 | |
Total Debt (4) to Bank EBITDA (2) (Maximum Ratio) | |
| 1.1:1.0 | | |
| 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, 2024, the Company's Senior Secured Debt totaled $630.6 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, 2024 was $2.3 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 including the impact of material acquisitions as if they had occurred at the beginning of the twelve month
period. Financing and interest expense for the twelve months ended June 30, 2024 was $219.0 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 payables, share-based compensation liability, dividends payable,
asset retirement obligations, leases, deferred income tax liabilities, other long-term liabilities and financial derivative liabilities.
As at June 30, 2024, the Company's Total Debt totaled $2.5 billion of principal amounts outstanding. |
At June 30, 2024, Baytex had $5.7 million
of outstanding letters of credit (December 31, 2023 - $5.6 million outstanding) under the Credit Facilities.
48 | Baytex Energy Corp. Second Quarter Report 2024 | |
| |
June 30, 2024 | | |
December 31, 2023 | |
8.75% notes due April 1, 2027 (1) | |
$ | — | | |
$ | 541,114 | |
8.50% notes due April 30, 2030 (2) | |
| 1,094,920 | | |
| 1,056,361 | |
7.375% notes due March 15, 2032 (3) | |
| 786,974 | | |
| — | |
Total long-term notes - principal (4) | |
| 1,881,894 | | |
| 1,597,475 | |
Unamortized debt issuance costs | |
| (48,712 | ) | |
| (35,114 | ) |
Total long-term notes - net of unamortized debt issuance costs | |
$ | 1,833,182 | | |
$ | 1,562,361 | |
| (1) | The 8.75% notes were fully repaid on April 1, 2024. The U.S. dollar denominated principal outstanding
of the 8.75% notes was US$409.8 million as at December 31, 2023. |
| (2) | The U.S. dollar denominated principal outstanding of the 8.50% notes was US$800.0 million as at June 30,
2024 (December 31, 2023 - US$800.0 million). |
| (3) | The U.S. dollar denominated principal outstanding of the 7.375% notes was US$575.0 million as at June 30,
2024 (December 31, 2023 - nil). |
| (4) | The increase in the principal amount of long-term notes outstanding from December 31, 2023 to
June 30, 2024 is the result of the issuance of the 7.375% notes for $780.9 million and changes in the reported amount of U.S. denominated
debt of $60.0 million due to changes in the CAD/USD exchange rate used to translate the U.S. denominated amount of long-term notes outstanding.
This was partially offset by the repayment of the 8.75% notes for $556.6 million. |
On April 1, 2024, Baytex closed a private
offering of the US$575 million aggregate principal amount of senior unsecured notes due 2032 ("7.375% Senior Notes"). The 7.375%
Senior Notes were priced at 99.266% of par to yield 7.500% per annum, bear interest at a rate of 7.375% per annum and mature on March 15,
2032. The 7.375% Senior Notes are redeemable at our option, in whole or in part, at specified redemption prices on or after March 15,
2027 and will be redeemable at par from March 15, 2029 to maturity. Proceeds from the 7.375% Senior Notes were used to redeem the
remaining US$409.8 million aggregate principal amount of the outstanding 8.75% Senior Notes at 104.375% of par value, pay the related
fees and expenses associated with the offering, and repay a portion of the debt outstanding on our Credit Facilities. During Q2 2024,
Baytex recorded early redemption expense of $24.4 million which is the call premium paid on the redemption of the 8.75% Senior Notes.
The long-term notes do not contain any significant
financial maintenance covenants but do contain standard commercial covenants for debt incurrence and restricted payments.
| Baytex Energy Corp. Second Quarter Report 2024 | 49 |
| 9. | ASSET RETIREMENT OBLIGATIONS |
| |
June 30, 2024 | | |
December 31, 2023 | |
Balance, beginning of period | |
$ | 623,399 | | |
$ | 588,923 | |
Liabilities incurred (1) | |
| 10,275 | | |
| 24,185 | |
Liabilities settled | |
| (13,626 | ) | |
| (26,416 | ) |
Liabilities assumed from corporate acquisition (note 3) | |
| — | | |
| 31,310 | |
Liabilities acquired from property acquisitions | |
| 81 | | |
| 11 | |
Liabilities divested | |
| (1,043 | ) | |
| (43,153 | ) |
Property swaps | |
| (728 | ) | |
| 76 | |
Accretion (note 15) | |
| 10,386 | | |
| 20,406 | |
Government grants (2) | |
| — | | |
| (1,271 | ) |
Change in estimate (1) | |
| 8,100 | | |
| 17,067 | |
Changes in discount and inflation rates
(1)(3) | |
| (17,084 | ) | |
| 12,914 | |
Foreign currency translation | |
| 3,265 | | |
| (653 | ) |
Balance, end of period | |
$ | 623,025 | | |
$ | 623,399 | |
Less current portion of asset retirement obligations | |
| 19,439 | | |
| 20,448 | |
Non-current portion of asset retirement obligations | |
$ | 603,586 | | |
$ | 602,951 | |
| (1) | The total of these items reflects the total change in asset retirement obligations of $1.3 million
per Note 6 - Oil and Gas Properties ($54.2 million increase in 2023). |
| (2) | Certain government grants were provided by the Government of Alberta and the Government of Saskatchewan
under programs that were completed during the year ended December 31, 2023. During the six months ended June 30, 2024, no amounts
have been recognized under these programs ($1.3 million for the year ended December 31, 2023). |
| (3) | The discount and inflation rates used to calculate the liability for our Canadian operations at June 30,
2024 were 3.4% and 1.8% respectively (December 31, 2023 - 3.0% and 1.6%). The discount and inflation rates used to calculate the
liability for our U.S. operations at June 30, 2024 were 4.5% and 2.3%, respectively (December 31, 2023 - 4.0% and 2.1%). |
The authorized capital of Baytex consists of an
unlimited number of common shares without nominal or par value and 10.0 million preferred shares without nominal or par value, issuable
in series. Baytex establishes the rights and terms of the preferred shares upon issuance. As at June 30, 2024, 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.
| |
Number of Common Shares (000s) | | |
Amount | |
Balance, December 31, 2022 | |
| 544,930 | | |
$ | 5,499,664 | |
Issued on corporate acquisition | |
| 311,370 | | |
| 1,326,435 | |
Vesting of share awards | |
| 5,892 | | |
| 26,229 | |
Common shares repurchased and cancelled | |
| (40,511 | ) | |
| (325,039 | ) |
Balance, December 31, 2023 | |
| 821,681 | | |
$ | 6,527,289 | |
Vesting of share awards | |
| 272 | | |
| 1,167 | |
Common shares repurchased and cancelled | |
| (16,976 | ) | |
| (137,348 | ) |
Balance, June 30, 2024 | |
| 804,977 | | |
$ | 6,391,108 | |
Normal Course Issuer Bid ("NCIB") Share Repurchases
On June 26, 2024, Baytex announced that the
Toronto Stock Exchange ("TSX") accepted the renewal of the NCIB under which Baytex is permitted to purchase for cancellation
up to 70.1 million common shares over the 12-month period commencing July 2, 2024. The number of shares authorized for repurchase
represented 10% of the Company's public float, as defined by the TSX, as at June 18, 2024. On June 18, 2024 Baytex had 808.0
million common shares outstanding.
During the six months ended June 30, 2024,
Baytex recorded $83.9 million related to common share repurchases, which includes $82.3 million of consideration paid for the repurchase
and cancellation of common shares as well as $1.6 million of federal tax levied on equity repurchases.
50 | Baytex Energy Corp. Second Quarter Report 2024 | |
Purchases are made on the open market at prices
prevailing at the time of the transaction. During the six months ended June 30, 2024, Baytex repurchased and cancelled 17.0 million
common shares at an average price of $4.85 per share for total consideration of $82.3 million. During 2023, Baytex repurchased and cancelled
40.5 million common shares at an average price of $5.48 per share for total consideration of $221.9 million. The total consideration paid
includes the commissions and fees paid as part of the transaction and is recorded as a reduction to shareholders' equity. The shares repurchased
and cancelled are accounted for as a reduction in shareholders' capital at historical cost, with any discount paid recorded to contributed
surplus and any premium paid recorded to retained earnings.
Effective January 1, 2024, the Government
of Canada introduced a 2% federal tax on equity repurchases. During the six months ended June 30, 2024, Baytex recorded a $1.6 million
liability, charged to shareholders’ capital, related to the federal tax on equity repurchases.
Dividends
The following dividends were declared by Baytex during the six months
ended June 30, 2024.
Record Date | |
Payable Date | |
Per Share Amount | | |
Dividend Amount | |
March 15, 2024 | |
April 1, 2024 | |
$ | 0.0225 | | |
$ | 18,494 | |
June 14, 2024 | |
July 2, 2024 | |
| 0.0225 | | |
| 18,161 | |
Total dividends declared | |
| |
| | | |
$ | 36,655 | |
On July 25, 2024, the Company's Board of
Directors declared a quarterly cash dividend of $0.0225 per share to be paid on October 1, 2024 for shareholders on record as at
September 16, 2024.
| 11. | SHARE-BASED COMPENSATION PLAN |
For the three and six months ended June 30,
2024 the Company recorded total share-based compensation expense of $5.6 million and $15.1 million respectively ($16.9 million and $26.7
million for the three and six months ended June 30, 2023) which is comprised of the expense related to cash-settled awards.
The Company's closing share price on the Toronto
Stock Exchange on June 30, 2024 was $4.74 (December 31, 2023 - $4.38 and June 30, 2023 - $4.32).
The number of awards outstanding is detailed below:
(000s) | |
| Restricted awards | | |
| Performance awards | | |
| Incentive awards | | |
| Director Share Units | | |
| Total | |
Total, December 31, 2022 | |
| 762 | | |
| 4,796 | | |
| 5,109 | | |
| 967 | | |
| 11,634 | |
Granted | |
| 41 | | |
| 2,641 | | |
| 2,607 | | |
| 278 | | |
| 5,567 | |
Assumed on corporate acquisition (1) | |
| 10,789 | | |
| — | | |
| — | | |
| — | | |
| 10,789 | |
Vested | |
| (9,302 | ) | |
| (3,767 | ) | |
| (2,715 | ) | |
| — | | |
| (15,784 | ) |
Forfeited | |
| (11 | ) | |
| (315 | ) | |
| (518 | ) | |
| — | | |
| (844 | ) |
Total, December 31, 2023 | |
| 2,279 | | |
| 3,355 | | |
| 4,483 | | |
| 1,245 | | |
| 11,362 | |
Granted | |
| 5 | | |
| 2,323 | | |
| 3,478 | | |
| 167 | | |
| 5,973 | |
Added by performance factor | |
| — | | |
| 524 | | |
| — | | |
| — | | |
| 524 | |
Vested | |
| (1,457 | ) | |
| (2,443 | ) | |
| (2,515 | ) | |
| — | | |
| (6,415 | ) |
Forfeited | |
| — | | |
| (20 | ) | |
| (56 | ) | |
| — | | |
| (76 | ) |
Total, June 30, 2024 | |
| 827 | | |
| 3,739 | | |
| 5,390 | | |
| 1,412 | | |
| 11,368 | |
| (1) | Following the closing of the
transaction, holders of awards outstanding under Ranger's Share Award Plan were entitled to Baytex common shares rather than Ranger common
shares with adjustment to the quantity outstanding based on the exchange ratio for Ranger shares. The fair value of share awards allocated
to consideration was based on the service period that had occurred prior to the acquisition date (note 3) while the remaining fair value
of the share awards assumed by Baytex is recognized over the remaining future service periods. |
| Baytex Energy Corp. Second Quarter Report 2024 | 51 |
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 share-based compensation liability.
In 2023, Baytex became the successor to Ranger's
Share Award Plan (note 3). Awards outstanding as at the closing day of the acquisition 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, 2024 was $4.28 per restricted and performance award ($5.41 for the six months ended
June 30, 2023).
Incentive Award Plan
Baytex has an Incentive Award Plan whereby the
participants of the plan are entitled to receive a cash payment equal to the value of one Baytex common share per incentive award at
the time of vesting. The incentive awards vest in equal tranches on the first, second and third anniversaries of the grant date. The
cumulative expense is recognized at fair value at each period end and is included in share-based compensation liability.
The weighted average fair value of share awards
granted during the six months ended June 30, 2024 was $4.28 per incentive award ($5.39 for the six months ended June 30, 2023).
Deferred Share Unit Plan ("DSU Plan")
Baytex has a DSU Plan whereby each independent
director of Baytex is entitled to receive a cash payment equal to the value of one Baytex common share per DSU award on the date at which
they cease to be a member of the Board. The awards vest immediately upon being granted and are expensed in full on the grant date. The
units are recognized at fair value at each period end and are included in share-based compensation liability.
The weighted average fair value of share awards
granted during the six months ended June 30, 2024 was $4.48 per DSU award ($5.49 for the six months ended June 30, 2023).
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 2024 | |
| |
Three
Months Ended June 30 | |
| |
2024 |
|
2023 | |
| |
| |
Weighted
average | |
| |
| |
Weighted
average | |
| |
| |
| |
common shares | |
Net income | |
| |
common shares | |
Net income | |
| |
Net
income | |
(000s) | |
per
share | |
Net
income | |
(000s) | |
per
share | |
Net income - basic | |
$ | 103,898 | |
814,151 | |
$ | 0.13 | |
$ | 213,603 | |
583,365 | |
$ | 0.37 | |
Dilutive effect of share
awards | |
| — | |
3,874 | |
| — | |
| — | |
4,805 | |
| — | |
Net income
- diluted | |
$ | 103,898 | |
818,025 | |
$ | 0.13 | |
$ | 213,603 | |
588,170 | |
$ | 0.36 | |
| |
Six Months Ended June 30 | |
| |
2024 | |
2023 | |
| |
| |
Weighted average | |
| |
| |
Weighted average | |
| |
| |
| |
common shares | |
Net income | |
| |
common shares | |
Net income | |
| |
Net income | |
(000s) | |
per share | |
Net income | |
(000s) | |
per share | |
Net income - basic | |
$ | 89,855 | |
817,931 | |
$ | 0.11 | |
$ | 265,044 | |
564,319 | |
$ | 0.47 | |
Dilutive effect of share awards | |
| — | |
3,359 | |
| — | |
| — | |
4,965 | |
| — | |
Net income - diluted | |
$ | 89,855 | |
821,290 | |
$ | 0.11 | |
$ | 265,044 | |
569,284 | |
$ | 0.47 | |
For the three and six months ended June 30,
2024 and June 30, 2023, no share awards were excluded from the calculation of diluted income per share as their effect was 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 | |
| |
2024 | | |
2023 | |
| |
Canada | | |
U.S. | | |
Total | | |
Canada | | |
U.S. | | |
Total | |
Light oil and condensate | |
$ | 104,030 | | |
$ | 558,620 | | |
$ | 662,650 | | |
$ | 124,965 | | |
$ | 183,845 | | |
$ | 308,810 | |
Heavy oil | |
| 394,960 | | |
| — | | |
| 394,960 | | |
| 251,449 | | |
| — | | |
| 251,449 | |
NGL | |
| 5,144 | | |
| 44,366 | | |
| 49,510 | | |
| 3,772 | | |
| 16,391 | | |
| 20,163 | |
Natural gas sales | |
| 4,426 | | |
| 21,577 | | |
| 26,003 | | |
| 10,106 | | |
| 8,232 | | |
| 18,338 | |
Total petroleum and natural gas sales | |
$ | 508,560 | | |
$ | 624,563 | | |
$ | 1,133,123 | | |
$ | 390,292 | | |
$ | 208,468 | | |
$ | 598,760 | |
| |
Six Months Ended June 30 | |
| |
2024 | | |
2023 | |
| |
Canada | | |
U.S. | | |
Total | | |
Canada | | |
U.S. | | |
Total | |
Light oil and condensate | |
$ | 199,251 | | |
$ | 1,064,514 | | |
$ | 1,263,765 | | |
$ | 271,420 | | |
$ | 325,855 | | |
$ | 597,275 | |
Heavy oil | |
| 699,884 | | |
| — | | |
| 699,884 | | |
| 468,534 | | |
| — | | |
| 468,534 | |
NGL | |
| 11,513 | | |
| 83,928 | | |
| 95,441 | | |
| 9,832 | | |
| 32,165 | | |
| 41,997 | |
Natural gas sales | |
| 14,225 | | |
| 44,000 | | |
| 58,225 | | |
| 26,128 | | |
| 20,162 | | |
| 46,290 | |
Total petroleum and natural gas sales | |
$ | 924,873 | | |
$ | 1,192,442 | | |
$ | 2,117,315 | | |
$ | 775,914 | | |
$ | 378,182 | | |
$ | 1,154,096 | |
Included in accounts receivable at June 30, 2024 is $362.7 million
of accrued receivables related to delivered volumes (December 31, 2023 - $271.1 million).
| Baytex Energy Corp. Second Quarter Report 2024 | 53 |
14. INCOME TAXES
The provision for income taxes has been computed as follows:
| |
Six Months Ended
June 30 | |
| |
2024 | | |
2023 | |
Net income before income taxes | |
$ | 136,621 | | |
$ | 104,677 | |
Expected income taxes at the statutory rate of 24.64% (2023
– 24.80%) | |
| 33,663 | | |
| 25,960 | |
Change in income taxes resulting from: | |
| | | |
| | |
Effect of foreign exchange | |
| 7,398 | | |
| (1,612 | ) |
Effect of rate adjustments for foreign
jurisdictions | |
| (5,085 | ) | |
| (2,883 | ) |
Effect
of change in deferred tax benefit not recognized (1) | |
| 2,145 | | |
| (1,613 | ) |
Effect
of internal debt restructuring (2) | |
| — | | |
| (186,460 | ) |
Repatriation and related taxes | |
| 7,413 | | |
| — | |
Adjustments, assessments
and other | |
| 1,232 | | |
| 6,241 | |
Income tax expense (recovery) | |
$ | 46,766 | | |
$ | (160,367 | ) |
| (1) | A deferred tax asset of $42.8 million
remains unrecognized due to uncertainty surrounding future commodity prices and future capital
gains (December 31, 2023 - $40.4 million). These deferred income tax assets relate to
capital losses of $161.9 million and non-capital losses of $92.9 million. |
In June 2016, certain indirect subsidiary
entities received reassessments from the Canada Revenue Agency ("CRA") that deny non-capital loss deductions relevant to the
calculation of income taxes for the years 2011 through 2015. Following objections and submissions, in November 2023 the CRA issued
notices of confirmation regarding their prior reassessments. In February 2024, Baytex filed notices of appeal with the Tax Court
of Canada and we estimate it could take between two and three years to receive a judgment. The reassessments do not require us to pay
any amounts in order to participate in the appeals process. Should we be unsuccessful at the Tax Court of Canada, additional appeals
are available; a process that we estimate could take another two years and potentially longer.
We remain confident that the tax filings of the
affected entities are correct and will defend our tax filing positions. During Q4/2023, we purchased $272.5 million of insurance coverage
for a premium of $50.3 million which will help manage the litigation risk associated with this matter. The most recent reassessments
issued by the CRA assert taxes owing by the trusts of $244.8 million, late payment interest of $208.6 million as at the date of reassessments
and a late filing penalty in respect of the 2011 tax year of $4.1 million.
By way of background, we acquired several privately
held commercial trusts in 2010 with accumulated non-capital losses of $591.0 million (the "Losses"). The Losses were subsequently
deducted in computing the taxable income of those trusts. The reassessments, as confirmed in November 2023, disallow the deduction
of the Losses for two reasons. First, the reassessments allege that the trusts were resettled and the resulting successor trusts were
not able to access the losses of the predecessor trusts. Second, the reassessments allege that the general anti-avoidance rule of
the Income Tax Act (Canada) operates to deny the deduction of the losses. If, after exhausting available appeals, the deduction of Losses
continues to be disallowed, either the trusts or their corporate beneficiary will owe cash taxes, late payment interest and potential
penalties. The amount of cash taxes owing, late payment interest and potential penalties are dependent upon the taxpayer(s) ultimately
liable (the trusts or their corporate beneficiary) and the amount of unused tax shelter available to the taxpayer(s) to offset the
reassessed income, including tax shelter from subsequent years that may be carried back and applied to prior years.
15. FINANCING AND INTEREST
| |
Three Months
Ended June 30 | | |
Six
Months Ended June 30 | |
| |
2024 | | |
2023 | | |
2024 | | |
2023 | |
Interest on Credit Facilities | |
$ | 15,639 | | |
$ | 7,535 | | |
$ | 33,928 | | |
$ | 13,751 | |
Interest on long-term notes | |
| 37,656 | | |
| 20,565 | | |
| 72,334 | | |
| 32,659 | |
Interest on lease obligations | |
| 651 | | |
| 155 | | |
| 964 | | |
| 220 | |
Cash interest | |
$ | 53,946 | | |
$ | 28,255 | | |
$ | 107,226 | | |
$ | 46,630 | |
Amortization of debt issue costs | |
| 7,862 | | |
| 1,847 | | |
| 10,922 | | |
| 2,371 | |
Accretion on asset retirement obligations (note 9) | |
| 5,459 | | |
| 4,395 | | |
| 10,386 | | |
| 9,221 | |
Early redemption expense (note 8) | |
| 24,350 | | |
| — | | |
| 24,350 | | |
| — | |
Financing and interest | |
$ | 91,617 | | |
$ | 34,497 | | |
$ | 152,884 | | |
$ | 58,222 | |
54 | Baytex Energy Corp. Second Quarter Report 2024 | |
16. FOREIGN EXCHANGE
| |
Three Months
Ended June 30 | | |
Six
Months Ended June 30 | |
| |
2024 | | |
2023 | | |
2024 | | |
2023 | |
Unrealized foreign exchange loss (gain) | |
$ | 19,189 | | |
$ | (12,880 | ) | |
$ | 57,907 | | |
$ | (13,093 | ) |
Realized foreign exchange loss | |
| 866 | | |
| 941 | | |
| 2,085 | | |
| 1,091 | |
Foreign exchange loss (gain) | |
$ | 20,055 | | |
$ | (11,939 | ) | |
$ | 59,992 | | |
$ | (12,002 | ) |
17. FINANCIAL INSTRUMENTS AND RISK
MANAGEMENT
The Company's financial assets and liabilities
are comprised of cash, trade receivables, trade payables, dividends payable, financial derivatives, Credit Facilities and long-term notes.
The fair value of trade receivables and trade 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,
2024 | |
December 31, 2023 | |
| |
| |
| |
| |
| |
Fair Value | |
| |
| |
| |
| |
| |
Measurement | |
| |
Carrying
value | |
Fair value | |
Carrying value | |
Fair value | |
Hierarchy | |
Financial Assets | |
| |
| |
| |
| |
| |
Fair value through profit and loss | |
| | |
| | |
| | |
| | |
| | |
Financial derivatives | |
$ | 7,028 | |
$ | 7,028 | |
$ | 23,274 | |
$ | 23,274 | |
| Level
2 | |
Total | |
$ | 7,028 | |
$ | 7,028 | |
$ | 23,274 | |
$ | 23,274 | |
| | |
| |
| | |
| | |
| | |
| | |
| | |
Amortized cost | |
| | |
| | |
| | |
| | |
| | |
Cash | |
$ | 35,887 | |
$ | 35,887 | |
$ | 55,815 | |
$ | 55,815 | |
| — | |
Trade receivables | |
| 429,098 | |
| 429,098 | |
| 339,405 | |
| 339,405 | |
| — | |
Total | |
$ | 464,985 | |
$ | 464,985 | |
$ | 395,220 | |
$ | 395,220 | |
| | |
| |
| | |
| | |
| | |
| | |
| | |
Financial Liabilities | |
| | |
| | |
| | |
| | |
| | |
Fair value through profit and loss | |
| | |
| | |
| | |
| | |
| | |
Financial derivatives | |
$ | (5,314 | ) |
$ | (5,314 | ) |
$ | — | |
$ | — | |
| Level
2 | |
Total | |
$ | (5,314 | ) |
$ | (5,314 | ) |
$ | — | |
$ | — | |
| | |
| |
| | |
| | |
| | |
| | |
| | |
Amortized cost | |
| | |
| | |
| | |
| | |
| | |
Trade payables | |
$ | (617,222 | ) |
$ | (617,222 | ) |
$ | (477,295 | ) |
$ | (477,295 | ) |
| — | |
Dividends payable | |
| (18,161 | ) |
| (18,161 | ) |
| (18,381 | ) |
| (18,381 | ) |
| — | |
Credit Facilities | |
| (607,589 | ) |
| (625,976 | ) |
| (848,749 | ) |
| (864,736 | ) |
| — | |
Long-term notes | |
| (1,833,182 | ) |
| (1,946,995 | ) |
| (1,562,361 | ) |
| (1,653,118 | ) |
| Level
1 | |
Total | |
$ | (3,076,154 | ) |
$ | (3,208,354 | ) |
$ | (2,906,786 | ) |
$ | (3,013,530 | ) |
| | |
There were no transfers between Level 1 and Level 2 during the six
months ended June 30, 2024 and 2023.
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, 2024 | |
December
31, 2023 | |
June
30, 2024 | |
December
31, 2023 | |
U.S. dollar denominated | |
US$ |
10,256 | |
US$ |
17,923 | |
US$ |
1,405,172 | |
US$ |
1,249,725 | |
| Baytex Energy Corp. Second Quarter Report 2024 | 55 |
Commodity Price Risk
Financial Derivative Contracts
As at July 25, 2024 Baytex had the following commodity financial
derivative contracts for the period subsequent to June 30, 2024.
| |
Remaining
Period | |
Volume | |
Price/Unit (1) | |
Index | |
Oil | |
| |
| |
| |
| |
Basis differential | |
July 2024
to Dec 2024 | |
15,000
bbl/d | |
Baytex pays: WCS differential at Hardisty | |
WCS | |
| |
| |
| |
Baytex receives: WCS differential
at Houston less US$8.31/bbl | |
| |
Basis differential | |
July 2024
to Dec 2024 | |
6,000
bbl/d | |
WTI less US$13.58/bbl | |
WCS | |
Basis differential | |
July 2024
to Dec 2024 | |
8,250
bbl/d | |
WTI less US$2.78/bbl | |
MSW | |
Basis differential | |
Jan
2025 to Dec 2025 | |
2,000
bbl/d | |
WTI less US$2.75/bbl | |
MSW | |
Collar | |
July 2024
to Dec 2024 | |
10,000
bbl/d | |
US$60.00/US$100.00 | |
WTI | |
Collar | |
July 2024
to Sep 2024 | |
10,000
bbl/d | |
US$60.00/US$100.00 | |
WTI | |
Collar | |
July 2024
to Dec 2024 | |
2,500
bbl/d | |
US$60.00/US$94.15 | |
WTI | |
Collar | |
July 2024
to Dec 2024 | |
1,500
bbl/d | |
US$60.00/US$90.35 | |
WTI | |
Collar | |
July 2024
to Dec 2024 | |
1,000
bbl/d | |
US$60.00/US$90.00 | |
WTI | |
Collar | |
July 2024
to Dec 2024 | |
2,000
bbl/d | |
US$60.00/US$85.00 | |
WTI | |
Collar | |
July 2024
to Dec 2024 | |
2,000
bbl/d | |
US$60.00/US$84.60 | |
WTI | |
Collar | |
July 2024
to Dec 2024 | |
5,000
bbl/d | |
US$60.00/US$84.15 | |
WTI | |
Collar | |
Oct
2024 to Dec 2024 | |
2,500
bbl/d | |
US$60.00/US$100.00 | |
WTI | |
Collar | |
Oct
2024 to Dec 2024 | |
3,500
bbl/d | |
US$60.00/US$87.10 | |
WTI | |
Collar | |
Oct
2024 to Dec 2024 | |
3,500
bbl/d | |
US$60.00/US$85.75 | |
WTI | |
Collar | |
Jan
2025 to Mar 2025 | |
5,000
bbl/d | |
US$60.00/US$88.70 | |
WTI | |
Collar | |
Jan
2025 to Mar 2025 | |
2,500
bbl/d | |
US$60.00/US$90.20 | |
WTI | |
Collar | |
Jan
2025 to Mar 2025 | |
2,500
bbl/d | |
US$60.00/US$90.05 | |
WTI | |
Collar | |
Jan
2025 to Mar 2025 | |
7,500
bbl/d | |
US$60.00/US$90.00 | |
WTI | |
Collar | |
Jan
2025 to Jun 2025 | |
2,500
bbl/d | |
US$60.00/US$94.25 | |
WTI | |
Collar | |
Jan
2025 to Jun 2025 | |
2,500
bbl/d | |
US$60.00/US$93.90 | |
WTI | |
Collar | |
Jan
2025 to Jun 2025 | |
5,000
bbl/d | |
US$60.00/US$91.95 | |
WTI | |
Collar | |
Jan
2025 to Jun 2025 | |
2,500
bbl/d | |
US$60.00/US$90.00 | |
WTI | |
Collar | |
Jan
2025 to Jun 2025 | |
3,000
bbl/d | |
US$60.00/US$89.55 | |
WTI | |
Collar | |
Apr
2025 to Jun 2025 | |
2,000
bbl/d | |
US$60.00/US$88.17 | |
WTI | |
Collar (2) | |
Apr
2025 to Jun 2025 | |
5,000
bbl/d | |
US$60.00/US$90.50 | |
WTI | |
Collar (2) | |
Apr
2025 to Jun 2025 | |
3,000
bbl/d | |
US$60.00/US$90.60 | |
WTI | |
Natural Gas | |
| |
| |
| |
| |
Collar | |
July 2024
to Dec 2024 | |
5,000
mmbtu/d | |
US$3.00/US$4.185 | |
NYMEX | |
Collar | |
July 2024
to Dec 2024 | |
8,500
mmbtu/d | |
US$3.00/US$4.15 | |
NYMEX | |
Collar | |
July 2024
to Dec 2024 | |
5,000
mmbtu/d | |
US$3.00/US$4.10 | |
NYMEX | |
Collar | |
July 2024
to Dec 2024 | |
2,500
mmbtu/d | |
US$3.00/US$4.09 | |
NYMEX | |
Collar | |
July 2024
to Dec 2024 | |
2,500
mmbtu/d | |
US$3.00/US$4.06 | |
NYMEX | |
Collar | |
Jan
2025 to Dec 2025 | |
7,000
mmbtu/d | |
US$3.00/US$4.01 | |
NYMEX | |
Collar | |
Jan
2025 to Dec 2025 | |
5,000
mmbtu/d | |
US$3.25/US$4.03 | |
NYMEX | |
Collar | |
Jan
2025 to Dec 2025 | |
5,000
mmbtu/d | |
US$3.25/US$4.08 | |
NYMEX | |
Collar | |
Jan
2025 to Dec 2025 | |
3,000
mmbtu/d | |
US$3.25/US$4.135 | |
NYMEX | |
Collar | |
Jan
2025 to Dec 2025 | |
5,500
mmbtu/d | |
US$3.25/US$4.14 | |
NYMEX | |
Collar | |
Jan
2025 to Dec 2025 | |
7,000
mmbtu/d | |
US$3.00/US$4.32 | |
NYMEX | |
Collar | |
Jan
2025 to Dec 2025 | |
3,000
mmbtu/d | |
US$3.00/US$4.85 | |
NYMEX | |
Collar | |
Jan
2025 to Dec 2025 | |
8,000
mmbtu/d | |
US$3.00/US$4.855 | |
NYMEX | |
Collar | |
Jan
2026 to Dec 2026 | |
11,000
mmbtu/d | |
US$3.25/US$5.02 | |
NYMEX | |
(1) Based
on the weighted average price per unit for the period.
(2) Contract
entered subsequent to June 30, 2024.
56 | Baytex Energy Corp. Second Quarter Report 2024 | |
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 | |
| |
2024 | | |
2023 | | |
2024 | | |
2023 | |
Realized
financial derivatives loss (gain) | |
$ | 2,257 | | |
$ | (16,365 | ) | |
$ | (3,231 | ) | |
$ | (21,780 | ) |
Unrealized
financial derivatives (gain) loss | |
| (10,790 | ) | |
| 19,403 | | |
| 21,560 | | |
| 10,193 | |
Financial
derivatives (gain) loss | |
$ | (8,533 | ) | |
$ | 3,038 | | |
$ | 18,329 | | |
$ | (11,587 | ) |
18. CAPITAL MANAGEMENT
The
Company's capital management objective is to maintain a strong balance sheet that provides financial flexibility to execute its development
programs, provide returns to shareholders and optimize its portfolio through strategic acquisitions. Baytex strives to actively manage
its capital structure in response to changes in economic conditions. At June 30, 2024, the Company's capital structure was comprised
of shareholders' capital, long-term notes, trade receivables, prepaids and other assets, trade payables, share-based compensation liability,
dividends payable, cash and the Credit Facilities.
In
order to manage its capital structure and liquidity, Baytex may from time-to-time issue equity or debt securities, enter into business
transactions including the sale of assets or adjust capital spending to manage current and projected debt levels. There is no certainty
that any of these additional sources of capital would be available if required.
The
capital-intensive nature of Baytex's operations requires the maintenance of adequate sources of liquidity to fund ongoing exploration
and development. Baytex's capital resources consist primarily of adjusted funds flow, available Credit Facilities and proceeds received
from the divestiture of oil and gas properties. The following capital management measures and ratios are used to monitor current and
projected sources of liquidity.
Net Debt
The
Company uses net debt to monitor its current financial position and to evaluate existing sources of liquidity. The Company defines net
debt to be the sum of our Credit Facilities and long-term notes outstanding adjusted for unamortized debt issuance costs, trade payables,
dividends payable, share-based compensation liability, other long-term liabilities, cash, trade receivables and prepaids and other assets.
Baytex also uses net debt projections to estimate future liquidity and whether additional sources of capital are required to fund ongoing
operations.
The following
table reconciles net debt to amounts disclosed in the primary financial statements.
| |
June 30, 2024 | | |
December
31, 2023 | |
Credit
Facilities | |
$ | 607,589 | | |
$ | 848,749 | |
Unamortized
debt issuance costs - Credit Facilities (note 7) | |
| 18,387 | | |
| 15,987 | |
Long-term
notes | |
| 1,833,182 | | |
| 1,562,361 | |
Unamortized
debt issuance costs - Long-term notes (note 8) | |
| 48,712 | | |
| 35,114 | |
Trade
payables | |
| 617,222 | | |
| 477,295 | |
Share-based
compensation liability | |
| 22,706 | | |
| 35,732 | |
Dividends
payable | |
| 18,161 | | |
| 18,381 | |
Other
long-term liabilities | |
| 19,845 | | |
| 19,147 | |
Cash | |
| (35,887 | ) | |
| (55,815 | ) |
Trade
receivables | |
| (429,098 | ) | |
| (339,405 | ) |
Prepaids
and other assets | |
| (81,805 | ) | |
| (83,259 | ) |
Net
Debt | |
$ | 2,639,014 | | |
$ | 2,534,287 | |
| Baytex Energy Corp. Second Quarter Report 2024 | 57 |
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 | |
| |
2024 | | |
2023 | | |
2024 | | |
2023 | |
Cash flows from operating activities | |
$ | 505,584 | | |
$ | 192,308 | | |
$ | 889,357 | | |
$ | 377,246 | |
Change in non-cash working capital | |
| 20,140 | | |
| 40,795 | | |
| 52,163 | | |
| 79,849 | |
Asset retirement obligations settled | |
| 7,115 | | |
| 5,392 | | |
| 13,626 | | |
| 9,518 | |
Transaction costs | |
| — | | |
| 32,832 | | |
| 1,539 | | |
| 41,703 | |
Cash premiums on derivatives | |
| — | | |
| 2,263 | | |
| — | | |
| 2,263 | |
Adjusted Funds Flow | |
$ | 532,839 | | |
$ | 273,590 | | |
$ | 956,685 | | |
$ | 510,579 | |
58 | Baytex Energy Corp. Second Quarter Report 2024 | |
ABBREVIATIONS
AECO |
the natural gas storage facility located at Suffield, Alberta |
bbl |
barrel |
bbl/d |
barrel per day |
boe* |
barrels of oil equivalent |
boe/d |
barrels of oil equivalent per day |
COSO |
Committee of Sponsoring Organizations of the Treadway Commission |
GAAP |
generally accepted accounting principles |
GJ |
gigajoule |
GJ/d |
gigajoule per day |
IAS |
International Accounting Standard |
IASB |
International Accounting Standards Board |
IFRS |
International Financial Reporting Standards |
LLS |
Louisiana Light Sweet |
mbbl |
thousand barrels |
mboe* |
thousand barrels of oil equivalent |
mcf |
thousand cubic feet |
mcf/d |
thousand cubic feet per day |
mmBtu |
million British Thermal Units |
mmBtu/d |
million British Thermal Units per day |
mmcf |
million cubic feet |
mmcf/d |
million cubic feet per day |
NGL |
natural gas liquids |
NYMEX |
New York Mercantile Exchange |
NYSE |
New York Stock Exchange |
TSX |
Toronto Stock Exchange |
WCS |
Western Canadian Select |
WTI |
West Texas Intermediate |
| * | Oil equivalent amounts may be misleading, particularly if used in isolation. In accordance with NI
51-101, a boe conversion ratio for natural gas of 6 Mcf: 1 bbl has been used, which is based on an energy equivalency conversion method
primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. |
| Baytex Energy Corp. Second Quarter Report 2024 | 59 |
CORPORATE INFORMATION
BOARD OF DIRECTORS
Mark R.
Bly
Chairman of
the Board
Eric T.
Greager
Director
Tiffany
(TJ) Thom Cepak 1,3
Director
Trudy M.
Curran 2,4
Director
Don G.
Hrap 1,3
Director
Angela
S. Lekatsas 1,4
Director
Jennifer
A. Maki 1,2
Director
David L.
Pearce 2,3
Director
Steve D.L.
Reynish 3,4
Director
Jeffrey
E. Wojahn 2,4
Director
| (1) | Member of the Audit Committee |
| (2) | Member of the Human Resources
and Compensation Committee |
| (3) | Member of the Reserves and Sustainability
Committee |
| (4) | Member of the Nominating and Governance
Committee |
HEAD OFFICE
Baytex
Energy Corp.
Centennial
Place, East Tower
2800, 520 - 3rd Avenue SW
Calgary, Alberta T2P 0R3
Toll-free 1.800.524.5521
T 587.952.3000
F 587.952.3001
BAYTEXENERGY.COM
Design: ARTHUR
/ HUNTER
Printing:
Merrill Corporation
OFFICERS
Eric T. Greager
President and
Chief Executive Officer
Chad L. Kalmakoff
Chief Financial Officer
Chad E. Lundberg
Chief Operating Officer
James R. Maclean
Chief Legal Officer
and
Corporate Secretary
Brian G. Ector
Senior Vice President,
Capital Markets and
Investor Relations
Kendall D. Arthur
Senior Vice President
and
General Manager, Canadian
Heavy Oil Operations
Julia C. Gwaltney
Senior Vice President
and
General Manager, U.S.
Eagle
Ford Operations
Nicole M. Frechette
Vice President and General
Manager,
Canadian Light Oil Operations
Chris M.P. Lessoway
Vice President,
Finance and Treasurer
AUDITORS
KPMG LLP
RESERVES ENGINEERS
McDaniel &
Associates Consultants Ltd.
TRANSFER AGENT
Odyssey Trust Company
EXCHANGE LISTINGS
New York Stock Exchange
Toronto Stock Exchange
Symbol: BTE
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