PR Newswire
CALGARY, AB
, Feb. 27, 2025 /PRNewswire/ – Veren Inc. (“Veren” or the “Company”) (TSX: VRN) (NYSE: VRN) is pleased to announce its operating and financial results for the fourth quarter and full year ended December 31, 2024.
KEY HIGHLIGHTS
- Generated significant excess cash flow of $642 million in 2024, through focused development of a high-quality asset base.
- Returned $386 million, or 60 percent of excess cash flow, to shareholders through dividends and share repurchases.
- Reduced net debt by 35 percent through a combination of excess cash flow generation and proceeds from dispositions.
- Replaced 173 percent of 2024 production on a 2P reserves basis, primarily driven by additions in the Alberta Montney.
- Expect to generate excess cash flow of $625 million to $825 million in 2025 based on US$70/bbl to US$75/bbl WTI.
“Last year marked a continued advancement in the execution of our long-term strategy as we significantly strengthened our balance sheet, consistently returned meaningful capital to our shareholders and achieved strong reserve additions,” said Craig Bryksa, President and CEO of Veren. “We are off to a great start in 2025 and remain focused on maximizing the long-term potential of our assets, supporting our commitment to shareholder returns and maintaining a strong financial position.”
FINANCIAL HIGHLIGHTS
Fourth Quarter 2024
- Adjusted funds flow totaled $619.6 million, or $1.01 per share diluted, driven by a strong operating netback of $36.56 per boe.
- Development capital expenditures, which included drilling and development, facilities and seismic costs, totaled $363.0 million. This included capital spending on facilities projects and improvements to further optimize the Company’s completions design in the Alberta Montney.
- The Company generated excess cash flow of $203.8 million, or $0.33 per share diluted.
- Veren closed its previously announced strategic sale of certain infrastructure assets in the Alberta Montney and directed net cash proceeds of $400 million to further strengthen the balance sheet. As at December 31, 2024, Veren’s net debt was $2.48 billion, or 1.0 times annualized adjusted funds flow, reflecting a reduction of $481.5 million in the quarter.
- The Company reported adjusted net earnings from operations of $247.0 million, or $0.40 per share diluted.
Full Year 2024
- Adjusted funds flow totaled $2.35 billion, or $3.79 per share diluted, driven by a strong operating netback of $36.83 per boe.
- Development capital expenditures, which included drilling and development, facilities and seismic costs, totaled $1.51 billion, in-line with the Company’s annual guidance range.
- The Company generated excess cash flow of $641.6 million, or $1.04 per share diluted.
- Veren reduced its net debt by $1.26 billion, or approximately 35 percent in 2024, through a combination of excess cash flow and proceeds received from the strategic disposition of non-core assets.
- The Company reported adjusted net earnings from operations of $848.8 million, or $1.37 per share diluted.
RETURN OF CAPITAL HIGHLIGHTS
Fourth Quarter 2024
- Veren returned $105.7 million to shareholders during the quarter. The Company paid a base dividend of $0.115 per share, or $70.7 million, and repurchased 4.6 million shares for $35.0 million through its normal course issuer bid during the quarter.
- Subsequent to the quarter, Veren’s Board of Directors declared a quarterly cash base dividend of $0.115 per share payable on April 1, 2025, to shareholders of record on March 15, 2025.
|
Adjusted funds flow, adjusted funds flow per share – diluted, excess cash flow, excess cash flow per share – diluted, operating netback, development capital expenditures, total return of capital, net debt, net debt to adjusted funds flow, net debt to annualized adjusted funds flow, net earnings from operations, adjusted net earnings from operations per share – diluted, base dividends, and base dividends per share – diluted are specified financial measures – refer to the Specified Financial Measures section in this press release for further information. All financial figures are approximate and in Canadian dollars unless otherwise noted. This press release contains forward-looking information and references to specified financial measures. Significant related assumptions and risk factors, and reconciliations are described under the Specified Financial Measures, Forward-Looking Statements and Reserves and Drilling Data sections of this press release, respectively. Further information breaking down the production information contained in this press release by product type can be found in the “Product Type Production Information” section of this press release. |
Full Year 2024
- Veren returned $385.7 million to shareholders, or 60 percent of excess cash flow, in 2024. This included the Company repurchasing a total of 10.4 million shares for $101.1 million during the year.
- Veren remains committed to returning 60 percent of its annual excess cash flow to shareholders through a combination of dividends and share repurchases.
OPERATIONAL HIGHLIGHTS
Fourth Quarter 2024
- Veren achieved fourth quarter average production of 188,721 boe/d, comprised of 64 percent oil and liquids, including strong December production of 190,296 boe/d. The Company’s Alberta Montney and Kaybob Duvernay assets contributed 77 percent of total production in the fourth quarter, with production from these key assets growing by 10 percent as compared to the first quarter of 2024.
- Veren brought two multi-well pads on stream in late fourth quarter in the Karr South area of its Alberta Montney asset which were completed using the single-point entry (“SPE”) design. These pads generated an average 30-day initial production (“IP30”) rate which exceeded the average type wells in the area by 30 percent, while producing at a strong light oil rate of 80 percent.
- During the fourth quarter, Veren initiated the capacity expansion of its Gold Creek West facility in the Alberta Montney to accommodate an expected increase in production from future pads. The Company also invested in significant gas egress infrastructure in the area and has successfully connected to multiple third-party gas plants to minimize future downtime. Building on Veren’s strong results from wells brought on stream in Gold Creek West in early 2024, the Company expects to bring a multi-well pad on stream in the area in late first quarter 2025.
- In the Kaybob Duvernay, the Company brought two multi-well pads on stream in the fourth quarter. These pads generated an average IP30 rate which exceeded the average type wells in the area by 25 percent, while producing at a strong condensate rate of 70 percent.
- Veren achieved responsibly sourced gas (RSG) certification under Equitable Origin’s EO100™ Standard for Responsible Development for its Alberta Montney asset’s natural gas production. The Company obtained this rigorous certification following an independent assessment of Veren’s performance targets within five areas: corporate governance, transparency and ethics; human rights, social impacts and community development; Indigenous Peoples’ rights; fair labour and working conditions; and climate change, biodiversity and environmental.
Full Year 2024
- The Company achieved annual average production of 191,163 boe/d in 2024, comprised of 65 percent oil and liquids, in-line with production guidance of 191,000 boe/d.
- Veren continued to focus on optimizing infrastructure in its Alberta Montney asset, which is expected to drive future operating cost savings, reduce downtime and enhance production capacity. The Company entered into a strategic partnership with Pembina Gas Infrastructure in 2024 which resulted in Veren operating all oil battery sites within its land position, while also acquiring priority access for all products and firm processing for 100 percent of capacity at the Patterson Creek Gas Plant. In addition, Veren invested in infield optimization projects throughout the play to increase operational flexibility and accommodate future growth in 2025 and throughout the five-year plan.
- During the year, the Company brought 57 wells on stream across 11 multi-well pads in the Alberta Montney. Veren plans to continue optimizing its completions by testing the SPE design in Karr and utilize SPE design in the Gold Creek area moving forward, as previously announced.
- Veren continued to deliver consistent results within its Kaybob Duvernay asset throughout 2024, demonstrating the strength of its operational execution. The Company brought 37 wells on stream across eight multi-well pads in the Volatile Oil window. Veren’s 2024 development program included several successful delineation wells on the eastern and western portion of the Company’s land position, derisking drilling inventory in these areas. Veren’s 2025 development program includes additional delineation drilling in the Liquids-Rich and Lean Gas windows of the play.
- The Company also continued to advance its decline mitigation initiatives in 2024, including successfully converting 35 producing wells to water injection wells. These initiatives support Veren’s low base decline rate of approximately 15 percent in its Saskatchewan assets, further enhancing its strong excess cash flow generation from the area. In 2025, the Company will continue to build on its operational momentum in the play by advancing its decline mitigation and open hole multi-lateral development programs.
RESERVE HIGHLIGHTS
- As previously announced, Veren’s Proved plus Probable (“2P”) reserves totaled 1,133.3 million boe (“MMboe”), Proved (“1P”) reserves totaled 739.1 MMboe and Proved Developed Producing (“PDP”) reserves totaled 333.1 MMboe at year-end 2024. The Company’s reserves were comprised of over 60 percent oil and liquids across all categories.
- The Company’s 2P reserve life index (“RLI”) is approximately 16 years based on mid-point of 2025 annual average production guidance.
- The Company achieved reserve additions of 121.4 MMboe on a 2P basis, excluding acquisitions and dispositions (“A&D”), replacing 173 percent of its 2024 annual production. On a 1P and PDP basis, the Company replaced 161 percent and 114 percent of its 2024 annual production, excluding A&D, respectively.
- Veren’s Alberta Montney asset contributed the majority of its 2P reserve additions, with the remaining additions coming from its Kaybob Duvernay asset. As at year-end 2024, over 65 percent of the Company’s total premium drilling locations in the Alberta Montney and Kaybob Duvernay were unbooked, allowing for future reserves growth.
- Veren generated 2P finding and development (“F&D”) costs, including change in future development capital (“FDC”), of $17.65 per boe, producing a recycle ratio of 2.1 times based on an operating netback of $36.83 per boe in 2024.
- Veren’s 2P FDC decreased by approximately $480 million to $9.19 billion, primarily driven by non-core asset dispositions completed in 2024.
OUTLOOK
Veren has had a strong start to 2025, generating 191,000 boe/d of production in January. The Company remains on track to meet its previously released full year annual average production guidance of 188,000 to 196,000 boe/d (65% oil and liquids), based on its development capital expenditures budget of $1.48 billion to $1.58 billion. Veren’s capital program is weighted to the first half of 2025, while its production is weighted to the second half of the year due to the timing of its development program and planned facilities downtime in early 2025. The Company will remain disciplined in the execution of its capital program, with the flexibility to adjust spending in response to market conditions in order to maximize long-term shareholder value.
Approximately 85 percent of the Company’s 2025 budget is allocated to its short-cycle Alberta Montney and Kaybob Duvernay assets, which provide top quartile returns, scalability and quick well payouts. Veren’s remaining capital is allocated to its long-cycle, low-decline Saskatchewan assets, which generate significant excess cash flow.
The Company continues to hedge a portion of its production as part of its ongoing commodity marketing and diversification program. Veren has hedged 35 percent of its oil and liquids production and 35 percent of its natural gas production for 2025, net of royalty interest. The Company has also diversified its natural gas pricing exposure, resulting in the majority of its production through 2026 receiving a combination of fixed prices and pricing related to major U.S. markets.
Veren expects to generate excess cash flow of $625 million to $825 million (US$70/bbl to US$75/bbl WTI and $2.25/Mcf AECO) in 2025, which is weighted to the second half of the year based on the timing of its development program and expected production growth. The Company will continue to target the return of 60 percent of its annual excess cash flow to shareholders through the base dividend and share repurchases, with the remaining 40 percent directed toward the balance sheet. Veren plans to increase the percentage of excess cash flow returned over time as the balance sheet strengthens further.
CONFERENCE CALL DETAILS
Veren’s management will host a conference call on Thursday, February 27, 2025 at 10:00 a.m. MT (12:00 p.m. ET) to discuss the Company’s results and outlook. A slide deck will accompany the conference call and can be found on Veren’s website.
Participants can listen to this event online via webcast. To join the call without operator assistance, participants may register online by entering their phone number to receive an instant automated call back. Alternatively, the conference call can be accessed with operator assistance by dialing 1–888–510–2154.
The webcast will be archived for replay and can be accessed online. The replay will be available shortly after the call’s completion.
The Company’s most recent investor presentation is available on Veren’s website.
2025 GUIDANCE
The Company’s guidance for 2025 is as follows:
|
|
188,000 – 196,000 |
|
|
$1,475 – $1,575 |
|
|
|
|
Annual operating expenses ($/boe) |
$12.75 – $13.75 |
|
Royalties |
10.75% – 11.75% |
|
1) |
Total annual average production (boe/d) is comprised of approximately 65% Oil, Condensate & NGLs and 35% Natural Gas. |
|
2) |
Specified financial measure that does not have any standardized meaning prescribed by IFRS and, therefore may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section for further information. |
|
3) |
Excludes capitalized administration of approximately $40 million, in addition to land expenditures and net property acquisitions and dispositions. Development capital expenditures spend is allocated on an approximate basis as follows: 85% drilling & development and 15% facilities & seismic. |
RETURN OF CAPITAL OUTLOOK
|
|
|
|
Current quarterly base dividend per share |
$0.115 |
|
|
|
|
% of excess cash flow (1) |
60 % |
|
1) |
Total return of capital is based on a framework that targets to return to shareholders 60% of excess cash flow on an annual basis |
The Company’s audited consolidated financial statements and management’s discussion and analysis for the year ended December 31, 2024, will be available on the System for Electronic Document Analysis and Retrieval (“SEDAR+”) at www.sedarplus.ca, on EDGAR at www.sec.gov and on Veren’s website at www.vrn.com.
|
Recycle ratio is specified financial measure – refer to the Specified Financial Measures section in this press release for further information. |
Summary of Reserves
The Company’s reserves were independently evaluated by McDaniel & Associates Consultants Ltd. (“McDaniel”) effective as at December 31, 2024. The reserves evaluation and reporting was conducted in accordance with the definitions, standards and procedures contained in the COGEH and National Instrument 51-101 Standards for Disclosure of Oil and Gas Activities (“NI 51-101”).
As at December 31, 2024(1) (2) (3) (4)
|
|
|
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Producing |
126,863 |
112,186 |
18,255 |
16,354 |
– |
– |
78,826 |
66,626 |
|
Proved Developed Non-Producing |
1,074 |
990 |
173 |
159 |
– |
– |
261 |
225 |
|
Proved Undeveloped |
112,787 |
95,668 |
2,038 |
1,905 |
– |
– |
107,985 |
91,557 |
|
Total Proved |
240,724 |
208,844 |
20,465 |
18,418 |
– |
– |
187,072 |
158,408 |
|
Total Probable |
139,147 |
116,479 |
8,025 |
7,059 |
– |
– |
89,436 |
69,176 |
|
Total Proved plus Probable |
379,871 |
325,324 |
28,490 |
25,477 |
– |
– |
276,508 |
227,584 |
|
|
|
|
||||
|
|
|
|
|
|
|
|
|
Proved Developed Producing |
647,859 |
600,392 |
6,969 |
7,504 |
333,081 |
296,482 |
|
Proved Developed Non-Producing |
4,265 |
4,044 |
55 |
45 |
2,228 |
2,056 |
|
Proved Undeveloped |
1,085,252 |
998,818 |
679 |
601 |
403,798 |
355,700 |
|
Total Proved |
1,737,377 |
1,603,253 |
7,702 |
8,151 |
739,108 |
654,238 |
|
Total Probable |
942,653 |
844,743 |
3,145 |
3,101 |
394,241 |
334,022 |
|
Total Proved plus Probable |
2,680,030 |
2,447,996 |
10,848 |
11,252 |
1,133,349 |
988,260 |
|
1) |
Based on three evaluator’s average (McDaniel, GLJ Ltd. and Sproule Associates Ltd.) January 1, 2025, escalated price forecast. |
|
2) |
Gross Reserves” are the total Company’s working-interest share before the deduction of any royalties and without including any royalty interest of the Company. |
|
3) |
“Net Reserves” are the total Company’s interest share after deducting royalties and including any royalty interest. |
|
4) |
Numbers may not add due to rounding. |
Summary of Before Tax Net Present Values
As at December 31, 2024(1)
|
|
||||||
|
|
||||||
|
|
|
|
|
|
|
|
|
|
Proved Developed Producing |
333,081 |
8,174 |
6,866 |
5,841 |
5,113 |
|
Total Proved |
739,108 |
15,484 |
11,910 |
9,420 |
7,702 |
|
|
Total Proved plus Probable |
1,133,349 |
27,298 |
18,934 |
14,040 |
10,967 |
|
|
1) |
Price deck based on three evaluator’s average (McDaniel, GLJ Ltd. and Sproule Associates Ltd.) January 1, 2025, escalated price forecast. |
RESERVES RECONCILIATION
Gross Reserves (1) (2) (3) (4)
|
|
|
|
|||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
238,989 |
142,434 |
381,422 |
46,823 |
33,119 |
79,942 |
21,163 |
6,677 |
27,840 |
|
Extensions and Improved Recovery |
32,259 |
3,402 |
35,661 |
240 |
(195) |
45 |
– |
– |
– |
|
Technical Revisions |
6,318 |
(729) |
5,589 |
2,191 |
(29) |
2,162 |
13 |
(11) |
2 |
|
Acquisitions |
544 |
200 |
744 |
– |
– |
– |
– |
– |
– |
|
Dispositions |
(11,793) |
(6,178) |
(17,971) |
(25,780) |
(24,902) |
(50,682) |
(20,586) |
(6,666) |
(27,252) |
|
Economic Factors |
6 |
18 |
25 |
152 |
32 |
184 |
– |
– |
– |
|
Production |
(25,600) |
– |
(25,600) |
(3,161) |
– |
(3,161) |
(590) |
– |
(590) |
|
|
240,724 |
139,147 |
379,871 |
20,465 |
8,025 |
28,490 |
– |
– |
– |
|
|
|
|
|||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
189,720 |
93,735 |
283,455 |
1,588,202 |
917,729 |
2,505,931 |
41,151 |
24,721 |
65,872 |
|
Extensions and Improved Recovery |
23,589 |
2,930 |
26,519 |
293,710 |
43,290 |
337,000 |
134 |
(74) |
60 |
|
Technical Revisions |
(711) |
(768) |
(1,480) |
10,419 |
(15,129) |
(4,711) |
1,180 |
(470) |
710 |
|
Acquisitions |
115 |
43 |
157 |
3,095 |
1,158 |
4,253 |
– |
– |
– |
|
Dispositions |
(8,464) |
(6,248) |
(14,712) |
(5,733) |
(2,264) |
(7,997) |
(33,074) |
(21,075) |
(54,149) |
|
Economic Factors |
(750) |
(255) |
(1,006) |
(8,647) |
(2,131) |
(10,777) |
(227) |
43 |
(183) |
|
Production |
(16,426) |
– |
(16,426) |
(143,669) |
– |
(143,669) |
(1,462) |
– |
(1,462) |
|
|
187,072 |
89,436 |
276,508 |
1,737,377 |
942,653 |
2,680,030 |
7,702 |
3,145 |
10,848 |
|
|
|||
|
|
|
|
|
|
|
768,254 |
433,040 |
1,201,294 |
|
Extensions and Improved Recovery |
105,063 |
13,339 |
118,402 |
|
Technical Revisions |
9,744 |
(4,137) |
5,607 |
|
Acquisitions |
1,174 |
436 |
1,611 |
|
Dispositions |
(73,090) |
(47,884) |
(120,975) |
|
Economic Factors |
(2,071) |
(553) |
(2,624) |
|
Production |
(69,966) |
– |
(69,966) |
|
|
739,108 |
394,241 |
1,133,349 |
|
1) |
Based on three evaluator’s average (McDaniel, GLJ Ltd. and Sproule Associates Ltd.) January 1, 2025, escalated price forecast. |
|
2) |
“Gross Reserves” are the total Company’s working-interest share before the deduction of any royalties and without including any royalty interest of the Company. |
|
3) |
Numbers may not add due to rounding |
Finding, Development and Acquisition Costs for 2024
|
|
|
|
|
|
|
|||
|
F&D |
1,550 |
1,550 |
1,550 |
|
Change in FDC on F&D |
(35) |
601 |
593 |
|
F&D Total (incl. change in FDC) |
1,515 |
2,151 |
2,143 |
|
FD&A |
545 |
545 |
545 |
|
Change in FDC on FD&A |
(42) |
230 |
(479) |
|
FD&A Total (incl. change in FDC) |
503 |
774 |
66 |
|
|
|||
|
Reserves Additions |
79,844 |
112,736 |
121,385 |
|
Reserves Additions incl. A&D |
21,945 |
40,820 |
2,021 |
|
|
|||
|
F&D Total (incl. change in FDC) |
$18.97 |
$19.08 |
$17.65 |
|
Recycle Ratio |
1.9 |
1.9 |
2.1 |
|
FD&A Total (incl. change in FDC) |
$22.93 |
$18.97 |
$32.53 |
|
Recycle Ratio |
1.6 |
1.9 |
1.1 |
|
1) |
Numbers may not add due to rounding. |
|
2) |
F&D and FD&A are calculated by dividing the identified capital expenditures by the applicable reserves additions. These can include or exclude changes in future development capital costs. |
|
3) |
Recycle ratio is calculated as operating netback before hedging divided by F&D or FD&A costs. Based on a 2024 operating netback of $36.83 per boe. |
|
4) |
F&D and FD&A costs includes capital expenditures associated with assets disposed of during the year. |
Future Development Capital
At year-end 2024, FDC for 2P reserves totaled $9.19 billion, compared to $9.67 billion at year-end 2023. The Company’s FDC decreased by approximately $480 million, primarily driven by non-core asset dispositions.
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|
||
|
|
|
|
|
2025 |
1,357 |
1,465 |
|
2026 |
1,308 |
1,375 |
|
2027 |
1,455 |
1,551 |
|
2028 |
1,314 |
1,679 |
|
2029 |
1,104 |
1,675 |
|
2030 |
33 |
1,023 |
|
2031 |
4 |
280 |
|
2032 |
4 |
132 |
|
2033 |
3 |
3 |
|
2034 |
3 |
3 |
|
2035 |
– |
– |
|
2036 |
– |
– |
|
Subtotal (1) |
6,586 |
9,186 |
|
Remainder |
– |
– |
|
Total (1) |
6,586 |
9,186 |
|
10% Discounted |
5,288 |
6,957 |
|
1) Numbers may not add due to rounding. |
CONSOLIDATED FINANCIAL AND OPERATING HIGHLIGHTS
|
Three months ended December 31 |
Year ended December 31 |
||||
|
(Cdn$ millions except per share and per boe amounts) |
|
2023 |
|
2023 |
|
|
|
|||||
|
Cash flow from operating activities |
|
611.3 |
|
2,195.7 |
|
|
Adjusted funds flow from operations (1) |
|
574.5 |
|
2,339.1 |
|
|
Per share (1) (2) |
|
1.03 |
|
4.27 |
|
|
Net income |
|
951.2 |
|
570.3 |
|
|
Per share (2) |
|
1.70 |
|
1.04 |
|
|
Adjusted net earnings from operations (1) |
|
192.8 |
|
932.6 |
|
|
Per share (1) (2) |
|
0.34 |
|
1.70 |
|
|
Dividends declared |
|
68.3 |
|
211.9 |
|
|
Per share (2) |
|
0.120 |
|
0.387 |
|
|
Net debt (1) |
|
3,738.1 |
|
3,738.1 |
|
|
Net debt to adjusted funds flow from operations (1) (3) |
|
1.6 |
|
1.6 |
|
|
Weighted average shares outstanding |
|||||
|
Basic |
|
556.5 |
|
545.6 |
|
|
Diluted |
|
559.1 |
|
548.3 |
|
|
|
|||||
|
Average daily production |
|||||
|
Crude oil and condensate (bbls/d) |
|
102,350 |
|
102,906 |
|
|
NGLs (bbls/d) |
|
17,528 |
|
19,017 |
|
|
Natural gas (mcf/d) |
|
254,345 |
|
224,926 |
|
|
Total (boe/d) |
|
162,269 |
|
159,411 |
|
|
Average selling prices (4) |
|||||
|
Crude oil and condensate ($/bbl) |
|
95.78 |
|
97.23 |
|
|
NGLs ($/bbl) |
|
28.08 |
|
29.86 |
|
|
Natural gas ($/mcf) |
|
2.79 |
|
3.08 |
|
|
Total ($/boe) |
|
67.82 |
|
70.67 |
|
|
|
|||||
|
Oil and gas sales |
|
67.82 |
|
70.67 |
|
|
Royalties |
|
(8.17) |
|
(9.13) |
|
|
Operating expenses |
|
(14.24) |
|
(14.62) |
|
|
Transportation expenses |
|
(3.82) |
|
(3.21) |
|
|
Operating netback(1) |
|
41.59 |
|
43.71 |
|
|
Realized gain on commodity derivatives |
|
0.17 |
|
0.19 |
|
|
Other (5) |
|
(3.28) |
|
(3.70) |
|
|
Adjusted funds flow from operations netback (1) |
|
38.48 |
|
40.20 |
|
|
|
|||||
|
Total capital acquisitions (1) (6) |
|
2,513.9 |
|
4,589.7 |
|
|
Total capital dispositions (1) (6) |
|
(602.4) |
|
(613.6) |
|
|
Development capital expenditures (1) |
|||||
|
Drilling and development |
|
239.1 |
|
1,016.9 |
|
|
Facilities and seismic |
|
39.8 |
|
121.8 |
|
|
Total |
|
278.9 |
|
1,138.7 |
|
|
Land expenditures |
|
2.2 |
|
33.6 |
|
|
(1) |
Specified financial measure that does not have any standardized meaning prescribed by IFRS and, therefore, may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section for further information. |
|
(2) |
The per share amounts (with the exception of dividends per share) are the per share – diluted amounts. |
|
(3) |
Net debt to adjusted funds flow from operations is calculated as the period end net debt divided by the sum of adjusted funds flow from operations for the trailing four quarters. |
|
(4) |
The average selling prices reported are before realized derivatives and transportation. |
|
(5) |
Other includes net purchased products, general and administrative expenses, interest on long-term debt, foreign exchange, cash-settled share-based compensation and certain cash items and excludes transaction costs, foreign exchange on US dollar long-term debt and certain non-cash items. |
|
(6) |
Capital acquisitions and dispositions, net represent total consideration for the transactions, including long-term debt and working capital assumed, and exclude transaction costs. |
FINANCIAL AND OPERATING HIGHLIGHTS FROM CONTINUING OPERATIONS
|
Three months ended December 31 |
Year ended December 31 |
|||
|
(Cdn$ millions except per share and per boe amounts) |
|
2023 |
|
2023 |
|
|
||||
|
Cash flow from operating activities from continuing operations |
|
524.0 |
|
1,796.7 |
|
Adjusted funds flow from continuing operations (1) |
|
535.1 |
|
1,975.6 |
|
Per share (1) (2) |
|
0.96 |
|
3.60 |
|
Net income from continuing operations |
|
302.6 |
|
799.4 |
|
Per share (2) |
|
0.54 |
|
1.46 |
|
Adjusted net earnings from continuing operations (1) |
|
210.0 |
|
795.9 |
|
Per share (1) (2) |
|
0.37 |
|
1.45 |
|
Weighted average shares outstanding |
||||
|
Basic |
|
556.5 |
|
545.6 |
|
Diluted |
|
559.1 |
|
548.3 |
|
|
||||
|
Average daily production from continuing operations |
||||
|
Crude oil and condensate (bbls/d) |
|
96,144 |
|
88,087 |
|
NGLs (bbls/d) |
|
16,023 |
|
15,026 |
|
Natural gas (mcf/d) |
|
248,306 |
|
211,275 |
|
Production from continuing operations (boe/d) |
|
153,551 |
|
138,326 |
|
Average selling prices from continuing operations (3) |
||||
|
Crude oil and condensate ($/bbl) |
|
94.64 |
|
95.87 |
|
NGLs ($/bbl) |
|
30.53 |
|
32.86 |
|
Natural gas ($/mcf) |
|
2.83 |
|
3.06 |
|
Total ($/boe) |
|
67.01 |
|
69.30 |
|
|
||||
|
Oil and gas sales |
|
67.01 |
|
69.30 |
|
Royalties |
|
(7.50) |
|
(7.43) |
|
Operating expenses |
|
(14.48) |
|
(15.26) |
|
Transportation expenses |
|
(3.96) |
|
(3.45) |
|
Operating netback (1) |
|
41.07 |
|
43.16 |
|
Realized gain on commodity derivatives |
|
0.18 |
|
0.31 |
|
Other (4) |
|
(3.37) |
|
(4.34) |
|
Adjusted funds flow from continuing operations netback (1) |
|
37.88 |
|
39.13 |
|
|
||||
|
Development capital expenditures from continuing operations (1) |
|
276.0 |
|
844.9 |
|
(1) |
Specified financial measure that does not have any standardized meaning prescribed by IFRS and, therefore, may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section for further information. |
|
(2) |
The per share amounts (with the exception of dividends per share) are the per share – diluted amounts. |
|
(3) |
The average selling prices reported are before realized derivatives and transportation. |
|
(4) |
Other includes net purchased products, general and administrative expenses, interest on long-term debt, foreign exchange, cash-settled share-based compensation and certain cash items and excludes transaction costs, foreign exchange on US dollar long-term debt and certain non-cash items. |
Specified Financial Measures
Throughout this press release, the Company uses the terms “total operating netback”, “total operating netback from continuing operations”, “total netback”, “total netback from continuing operations”, “operating netback”, “netback”, “adjusted funds flow from operations” (or “adjusted FFO”), “adjusted funds flow from operations per share – diluted”, “adjusted funds flow from continuing operations”, “adjusted funds flow from continuing operations per share – diluted” “adjusted funds flow from discontinued operations”, “adjusted funds flow from operations netback”, “adjusted funds flow from continuing operations netback”, “excess cash flow”, “excess cash flow per share – diluted”, “base dividends”, “base dividends per share – diluted”, “total return of capital”, “adjusted working capital surplus (deficiency)”, “net debt”, “net debt to adjusted funds flow from operations”, “net debt to annualized adjusted funds flow”, “adjusted net earnings from operations”, “adjusted net earnings from operations per share – diluted”, “adjusted net earnings from continuing operations”, “adjusted net earnings from continuing operations per share – diluted”, “adjusted net earnings from discontinued operations”, “development capital expenditures”, “development capital expenditures from continuing operations”, “development capital expenditures from discontinued operations”, “recycle ratio”, “total capital acquisitions” and “total capital dispositions”. These terms do not have any standardized meaning as prescribed by IFRS and, therefore, may not be comparable with the calculation of similar measures presented by other issuers. For information on the composition of these measures and how the Company uses these measures, refer to the Specified Financial Measures section of the Company’s MD&A for the year ended December 31, 2024, which section is incorporated herein by reference, and available on SEDAR+ at www.sedarplus.ca and on EDGAR at www.sec.gov/edgar.
Adjusted funds flow from operations netback is a non-GAAP financial ratio and is calculated as adjusted funds flow from operations divided by total production. Adjusted funds flow from operations netback is a common metric used in the oil and gas industry and is used to measure operating results on a per boe basis.
The following table reconciles oil and gas sales to total operating netback from continuing operations, total netback from continuing operations and total adjusted funds flow from continuing operations netback.
|
Three months ended December 31 |
Year ended December 31 |
|||||
|
($ millions) |
|
2023 |
% Change |
|
2023 |
% Change |
|
Oil and gas sales |
|
946.7 |
9 |
|
3,499.0 |
22 |
|
Royalties |
|
(105.9) |
(2) |
|
(375.3) |
18 |
|
Operating expenses |
|
(204.5) |
8 |
|
(770.5) |
22 |
|
Transportation expenses |
|
(56.0) |
32 |
|
(174.3) |
79 |
|
Total operating netback from continuing operations |
|
580.3 |
9 |
|
2,178.9 |
18 |
|
Realized gain on commodity derivatives |
|
2.5 |
1,384 |
|
15.5 |
363 |
|
Total netback from continuing operations |
|
582.8 |
15 |
|
2,194.4 |
21 |
|
Other (1) |
|
(47.7) |
9 |
|
(218.8) |
37 |
|
Total adjusted funds flow from continuing operations netback |
|
535.1 |
16 |
|
1,975.6 |
19 |
|
(1) Other includes net purchased products, general and administrative expenses, interest on long-term debt, foreign exchange, cash-settled share-based compensation and certain cash items and excludes transaction costs, foreign exchange on US dollar long-term debt and certain non-cash items. |
The following table reconciles cash flow from operating activities to adjusted funds flow from operations and excess cash flow:
|
Three months ended December 31 |
Year ended December 31 |
|||||
|
($ millions) |
|
2023 |
% Change |
|
2023 |
% Change |
|
Cash flow from operating activities |
|
611.3 |
(16) |
|
2,195.7 |
(4) |
|
Changes in non-cash working capital |
|
(82.0) |
(211) |
|
54.9 |
220 |
|
Transaction costs |
|
31.8 |
(88) |
|
48.5 |
(59) |
|
Decommissioning expenditures (1) |
|
13.4 |
(11) |
|
40.0 |
2 |
|
Adjusted funds flow from operations |
|
574.5 |
8 |
|
2,339.1 |
— |
|
Development capital and other expenditures |
|
(292.1) |
29 |
|
(1,220.5) |
30 |
|
Payments on principal portion of lease liability |
|
(4.6) |
213 |
|
(20.8) |
97 |
|
Decommissioning expenditures |
|
(13.4) |
(11) |
|
(40.0) |
2 |
|
Unrealized loss on equity derivative contracts |
|
(5.7) |
(56) |
|
(29.3) |
(68) |
|
Transaction costs |
|
(31.8) |
(88) |
|
(48.5) |
(59) |
|
Other items (2) |
|
1.9 |
(400) |
|
1.6 |
(581) |
|
Excess cash flow |
|
228.8 |
(11) |
|
981.6 |
(35) |
|
(1) Excludes amounts received from government grant programs. |
|
(2) Other items exclude net acquisitions and dispositions. |
The following table reconciles cash flow from operating activities from discontinued operations to adjusted funds flow from discontinued operations:
|
Three months ended December 31 |
Year ended December 31 |
|||||
|
($ millions) |
|
2023 |
% Change |
|
2023 |
% Change |
|
Cash flow from operating activities from discontinued operations |
|
87.3 |
(100) |
|
399.0 |
(100) |
|
Changes in non-cash working capital |
|
(57.0) |
(100) |
|
(44.6) |
(100) |
|
Transaction costs |
|
8.7 |
(100) |
|
8.7 |
(100) |
|
Decommissioning expenditures (1) |
|
0.4 |
(100) |
|
0.4 |
(100) |
|
Adjusted funds flow from discontinued operations |
|
39.4 |
— |
|
363.5 |
— |
|
(1) Excludes amounts received from government grant programs. |
The following tables reconcile cash flow from operating activities and adjusted funds flow from operations from continuing and discontinued operations:
|
Three months ended December 31 |
Year ended December 31 |
|||||
|
($ millions) |
|
2023 |
% Change |
|
2023 |
% Change |
|
Cash flow from operating activities from continuing operations |
|
524.0 |
(2) |
|
1,796.7 |
18 |
|
Cash flow from operating activities from discontinued operations |
|
87.3 |
(100) |
|
399.0 |
(100) |
|
Cash flow from operating activities |
|
611.3 |
(16) |
|
2,195.7 |
(4) |
|
Three months ended December 31 |
Year ended December 31 |
|||||
|
($ millions) |
|
2023 |
% Change |
|
2023 |
% Change |
|
Adjusted funds flow from continuing operations |
|
535.1 |
16 |
|
1,975.6 |
19 |
|
Adjusted funds flow from discontinued operations |
|
39.4 |
(100) |
|
363.5 |
(100) |
|
Adjusted funds flow from operations |
|
574.5 |
8 |
|
2,339.1 |
— |
Adjusted funds flow from operations per share – diluted is a supplementary financial measure and is calculated as adjusted funds flow from operations divided by the number of weighted average diluted shares outstanding.
The following table reconciles adjusted working capital deficiency:
|
($ millions) |
|
December 31, 2023 |
% Change |
|
Accounts payable and accrued liabilities |
|
634.9 |
(22) |
|
Dividends payable |
|
56.8 |
24 |
|
Long-term compensation liability (1) |
|
66.8 |
(29) |
|
Cash |
|
(17.3) |
(1) |
|
Accounts receivable |
|
(377.9) |
2 |
|
Prepaids and deposits |
|
(87.8) |
13 |
|
Deferred consideration receivable (2) |
|
(79.2) |
(77) |
|
Adjusted working capital deficiency |
|
196.3 |
(54) |
|
(1) Includes current portion of long-term compensation liability and is net of equity derivative contracts. |
|
(2) Deferred consideration receivable is comprised of $7.2 million included in other current assets and $10.8 million included in other long-term assets (December 31, 2023 – $79.2 million in other current assets and nil in other long-term assets). |
The following table reconciles long-term debt to net debt:
|
($ millions) |
|
December 31, 2023 |
% Change |
|
Long-term debt (1) |
|
3,566.3 |
(31) |
|
Adjusted working capital deficiency |
|
196.3 |
(54) |
|
Unrealized foreign exchange on translation of hedged US dollar long-term debt |
|
(24.5) |
176 |
|
Net debt |
|
3,738.1 |
(34) |
|
(1) Includes current portion of long-term debt. |
The following table reconciles net income to adjusted net earnings from operations:
|
Three months ended December 31 |
Year ended December 31 |
|||||
|
($ millions) |
|
2023 |
% Change |
|
2023 |
% Change |
|
Net income |
|
951.2 |
(85) |
|
570.3 |
(52) |
|
Amortization of E&E undeveloped land |
|
12.0 |
167 |
|
30.9 |
297 |
|
Impairment |
|
48.4 |
(100) |
|
822.2 |
(38) |
|
Unrealized derivative (gains) losses |
|
(98.5) |
(145) |
|
56.9 |
(3) |
|
Unrealized foreign exchange (gain) loss on translation of hedged US dollar long-term debt |
|
(95.4) |
(169) |
|
(168.6) |
(131) |
|
Net loss on capital dispositions |
|
13.7 |
(20) |
|
9.6 |
122 |
|
Reclassification of cumulative foreign currency translation of discontinued foreign operations |
|
(621.7) |
(100) |
|
(621.7) |
(100) |
|
Deferred tax adjustments |
|
(16.9) |
212 |
|
233.0 |
(180) |
|
Adjusted net earnings from operations |
|
192.8 |
28 |
|
932.6 |
(9) |
The following table reconciles net income (loss) from discontinued operations to adjusted net earnings from discontinued operations:
|
Three months ended December 31 |
Year ended December 31 |
|||||
|
($ millions) |
|
2023 |
% Change |
|
2023 |
% Change |
|
Net income (loss) from discontinued operations |
|
648.6 |
(100) |
|
(229.1) |
(95) |
|
Impairment |
|
— |
— |
|
728.4 |
(100) |
|
Unrealized derivative (gains) losses |
|
(5.1) |
(100) |
|
18.9 |
(100) |
|
Net (gain) loss on capital dispositions |
|
9.0 |
(118) |
|
9.0 |
23 |
|
Reclassification of cumulative foreign currency translation of discontinued foreign operations |
|
(621.7) |
(100) |
|
(621.7) |
(100) |
|
Deferred tax adjustments |
|
(48.0) |
(100) |
|
231.2 |
(100) |
|
Adjusted net earnings from discontinued operations |
|
(17.2) |
(100) |
|
136.7 |
(100) |
The following table reconciles adjusted net earnings from continuing and discontinued operations:
|
Three months ended December 31 |
Year ended December 31 |
|||||
|
($ millions) |
|
2023 |
% Change |
|
2023 |
% Change |
|
Adjusted net earnings from continuing operations |
|
210.0 |
18 |
|
795.9 |
7 |
|
Adjusted net earnings (loss) from discontinued operations |
|
(17.2) |
(100) |
|
136.7 |
(100) |
|
Adjusted net earnings from operations |
|
192.8 |
28 |
|
932.6 |
(9) |
The following table reconciles development capital and other expenditures to development capital expenditures:
|
Three months ended December 31 |
Year ended December 31 |
|||||
|
($ millions) |
|
2023 |
% Change |
|
2023 |
% Change |
|
Development capital and other expenditures |
|
292.1 |
29 |
|
1,220.5 |
30 |
|
Payments on drilling rig lease liabilities |
|
— |
100 |
|
— |
100 |
|
Land expenditures |
|
(2.2) |
155 |
|
(33.6) |
24 |
|
Capitalized administration (1) |
|
(8.9) |
15 |
|
(42.3) |
7 |
|
Corporate assets |
|
(2.1) |
(5) |
|
(5.9) |
(3) |
|
Development capital expenditures |
|
278.9 |
30 |
|
1,138.7 |
32 |
|
(1) Capitalized administration excludes capitalized equity-settled SBC. |
The following table reconciles development capital expenditures from continuing and discontinued operations:
|
Three months ended December 31 |
Year ended December 31 |
|||||
|
($ millions) |
|
2023 |
% Change |
|
2023 |
% Change |
|
Development capital expenditures from continuing operations |
|
276.0 |
32 |
|
844.9 |
78 |
|
Development capital expenditures from discontinued operations |
|
2.9 |
(100) |
|
293.8 |
(100) |
|
Development capital expenditures |
|
278.9 |
30 |
|
1,138.7 |
32 |
The following table reconciles capital acquisitions, net of cash acquired to total capital acquisitions:
|
Three months ended December 31 |
Year ended December 31 |
|||||||||||
|
($ millions) |
|
2023 |
% Change |
|
2023 |
% Change |
||||||
|
Capital acquisitions, net of cash acquired |
|
1,540.4 |
(100) |
|
3,616.2 |
(99) |
||||||
|
Common shares issued on capital acquisition |
|
493.0 |
(100) |
|
493.0 |
(100) |
||||||
|
Working capital acquired through capital acquisition |
|
116.7 |
(95) |
|
116.7 |
(95) |
||||||
|
Long-term debt acquired through capital acquisition |
|
363.8 |
(100) |
|
363.8 |
(100) |
||||||
|
Total capital acquisitions |
|
2,513.9 |
(100) |
|
4,589.7 |
(99) |
||||||
The following table reconciles capital dispositions to total capital dispositions:
|
Three months ended December 31 |
Year ended December 31 |
|||||||||||
|
($ millions) |
|
2023 |
% Change |
|
2023 |
% Change |
||||||
|
Capital dispositions |
|
(593.3) |
(34) |
|
(604.5) |
72 |
||||||
|
Working capital disposed through capital disposition |
|
(9.1) |
(100) |
|
(9.1) |
(100) |
||||||
|
Total capital dispositions |
|
(602.4) |
(35) |
|
(613.6) |
69 |
||||||
Total return of capital is a supplementary financial measure and is comprised of base dividends, special dividends and share repurchases, adjusted for the timing of special dividend payments.
Net debt to annualized adjusted funds flow is calculated as the period end net debt divided by the quarterly adjusted funds flow from operations multiplied by four. Net debt to annualized adjusted funds flow for the three months ended December 31, 2023 was 1.6 times.
Excess cash flow for 2025 is a forward-looking non-GAAP measures and is calculated consistently with the measures disclosed in the Company’s MD&A. Refer to the Specified Financial Measures section of the Company’s MD&A for the year ended December 31, 2024.
Recycle ratio is a non-GAAP ratio and is calculated as operating netback before hedging divided by FD&A costs. Recycle ratios may not be comparable year-over-year given significant changes executed. Recycle ratio is a common metric used in the oil and gas industry and is used to measure profitability on a per boe basis.
|
|
|
|
|
|
|
|||
|
F&D Total (incl. change in FDC) |
1.2 |
1.5 |
2.2 |
|
FD&A Total (incl. change in FDC) |
1.2 |
1.9 |
2.5 |
Management believes the presentation of the specified financial measures above provide useful information to investors and shareholders as the measures provide increased transparency and the ability to better analyze performance against prior periods on a comparable basis.
Notice to US Readers
All amounts in the news release are stated in Canadian dollars unless otherwise specified.
The oil and natural gas reserves contained in this press release have generally been prepared in accordance with Canadian disclosure standards, which are not comparable in all respects of United States or other foreign disclosure standards. For example, the United States Securities and Exchange Commission (the “SEC”) generally permits oil and gas issuers, in their filings with the SEC, to disclose only proved reserves (as defined in SEC rules), but permits the optional disclosure of “probable reserves” and “possible reserves” (each as defined in SEC rules). Canadian securities laws require oil and gas issuers, in their filings with Canadian securities regulators, to disclose not only proved reserves (which are defined differently from the SEC rules) but also probable reserves and permits optional disclosure of “possible reserves”, each as defined in NI 51-101. Accordingly, “proved reserves”, “probable reserves” and “possible reserves” disclosed in this news release may not be comparable to US standards, and in this news release, Veren has disclosed reserves designated as “proved plus probable reserves”. Probable reserves are higher-risk and are generally believed to be less likely to be accurately estimated or recovered than proved reserves. “Possible reserves” are higher risk than “probable reserves” and are generally believed to be less likely to be accurately estimated or recovered than “probable reserves”. In addition, under Canadian disclosure requirements and industry practice, reserves and production are reported using gross volumes, which are volumes prior to deduction of royalties and similar payments. The SEC rules require reserves and production to be presented using net volumes, after deduction of applicable royalties and similar payments. Moreover, Veren has determined and disclosed estimated future net revenue from its reserves using forecast prices and costs, whereas the SEC rules require that reserves be estimated using a 12-month average price, calculated as the arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. Consequently, Veren’s reserve estimates and production volumes in this news release may not be comparable to those made by companies using United States reporting and disclosure standards. Further, the SEC rules are based on unescalated costs and forecasts.
Forward-Looking Statements
Any “financial outlook” or “future oriented financial information” in this press release, as defined by applicable securities legislation has been approved by management of Veren. Such financial outlook or future oriented financial information is provided for the purpose of providing information about management’s current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes.
Certain statements contained in this press release constitute “forward-looking statements” within the meaning of section 27A of the Securities Act of 1933 and section 21E of the Securities Exchange Act of 1934 and “forward-looking information” for the purposes of Canadian securities regulation (collectively, “forward-looking statements”). The Company has tried to identify such forward-looking statements by use of such words as “could”, “should”, “can”, “anticipate”, “expect”, “believe”, “will”, “may”, “intend”, “projected”, “sustain”, “continues”, “strategy”, “potential”, “projects”, “grow”, “take advantage”, “estimate”, “well-positioned” and other similar expressions, but these words are not the exclusive means of identifying such statements.
In particular, this press release contains forward-looking statements pertaining, among other things, to the following: expected 2025 excess cash flow at the commodity prices specified, focuses for 2025; extent of hedging program and natural gas pricing diversification; return of capital outlook, including base dividend, and the additional return of capital targeted as a percentage of excess cash flow; increasing expected production from future pads in Gold Creek West; timing to bring a multi-well pad on stream in Gold Creek West; testing and utilizing the SPE design; benefits of optimizing infrastructure in the Alberta Montney; benefits of strategic partnership with Pembina Gas Infrastructure; future growth in the Alberta Montney and throughout the five-year plan; benefits of infield optimization in the Alberta Montney; Veren’s 2025 development program, including, but not limited to, drilling plans and areas of focus in the Kaybob Duvernay; Saskatchewan base decline rate; operational momentum in Saskatchewan and advancing decline mitigation and open hole multi-lateral development programs in Saskatchewan; NAV; NPV; independent engineering price forecast; unbooked locations and future reserves growth; Veren’s 2025 total annual average production (including oil and liquids percentages) and development capital expenditures guidance (and components thereof); and other information for Veren’s 2025 guidance, including annual operating expenses and royalties; remaining disciplined in the execution of its 2025 capital program, with the flexibility to adjust spending in response to market conditions in order to maximize long-term shareholder value; 2025 budget allocation by area and area attributes, expectations and focuses; 2025 capital program and production timing; 2025 timing of development program and planned facilities downtime; 2025 excess cash flow generation at the commodity prices specified and timing thereof; return of capital outlook and percentage of annual excess cash flow to be returned to shareholders and methods thereof; and plans to increase the percentage of excess cash flow returned to shareholders as the balance sheet strengthens further.
Statements relating to “reserves” are also deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future. Actual reserve values may be greater than or less than the estimates provided herein.
Unless otherwise noted, reserves referenced herein are given as at December 31, 2024. Also, estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates and future net revenue for all properties due to the effect of aggregation. All required reserve information for the Company is contained in its Annual Information Form for the year ended December 31, 2024, which is accessible at www.sedarplus.ca.
With respect to disclosure contained herein regarding resources other than reserves, there is uncertainty that it will be commercially viable to produce any portion of the resources and there is significant uncertainty regarding the ultimate recoverability of such resources.
All forward-looking statements are based on Veren’s beliefs and assumptions based on information available at the time the assumption was made. Veren believes that the expectations reflected in these forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this report should not be unduly relied upon. By their nature, such forward-looking statements are subject to a number of risks, uncertainties and assumptions, which could cause actual results or other expectations to differ materially from those anticipated, expressed or implied by such statements, including those material risks discussed in the Company’s Annual Information Form for the year ended December 31, 2024 under “Risk Factors” and our Management’s Discussion and Analysis for the year ended December 31, 2024, under the headings “Risk Factors” and “Forward-Looking Information”. The material assumptions are disclosed in the Management’s Discussion and Analysis for the year ended December 31, 2024, under the headings “Capital Expenditures”, “Liquidity and Capital Resources”, “Critical Accounting Estimates”, “Risk Factors” and “Changes in Accounting Policies”. In addition, risk factors include: financial risk of marketing reserves at an acceptable price given market conditions; volatility in market prices for oil and natural gas, decisions or actions of OPEC and non-OPEC countries in respect of supplies of oil and gas; delays in business operations or delivery of services due to pipeline restrictions, rail blockades, outbreaks, pandemics, and blowouts; the risk of carrying out operations with minimal environmental impact; industry conditions including changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced, including but not limited to the adoption of emissions caps; uncertainties associated with estimating oil and natural gas reserves; risks and uncertainties related to oil and gas interests and operations on Indigenous lands; economic risk of finding and producing reserves at a reasonable cost; uncertainties associated with partner plans and approvals; operational matters related to non-operated properties; increased competition for, among other things, capital, acquisitions of reserves and undeveloped lands; competition for and availability of qualified personnel or management; incorrect assessments of the value and likelihood of acquisitions and dispositions, and exploration and development programs; unexpected geological, technical, drilling, construction, processing and transportation problems; the impacts of drought, wildfires and severe weather events; availability of insurance; fluctuations in foreign exchange and interest rates; stock market volatility; general economic, market and business conditions, including uncertainty in the demand for oil and gas and economic activity in general; changes in interest rates and inflation; uncertainties associated with regulatory approvals; geopolitical conflicts, including the Russian invasion of Ukraine and conflict in the Middle East; uncertainty of government policy changes; the potential for tariffs and the impact of the renegotiation or implementation of the Canada-United States-Mexico Agreement; uncertainty regarding the benefits and costs of dispositions; failure to complete acquisitions and dispositions; uncertainties associated with credit facilities and counterparty credit risk; and changes in income tax laws, tax laws, crown royalty rates and incentive programs relating to the oil and gas industry; and other factors, many of which are outside the control of the Company. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and Veren’s future course of action depends on management’s assessment of all information available at the relevant time.
Included in this press release are Veren’s 2025 guidance in respect of capital expenditures and average annual production which is based on various assumptions as to production levels, commodity prices and other assumptions and are subject to a variety of contingencies. The Company’s return of capital framework is based on certain facts, expectations and assumptions that may change and, therefore, this framework may be amended as circumstances necessitate or require. To the extent such estimates constitute a “financial outlook” or “future oriented financial information” in this press release, as defined by applicable securities legislation, such information has been approved by management of Veren. Such financial outlook or future oriented financial information is provided for the purpose of providing information about management’s current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes.
Additional information on these and other factors that could affect Veren’s operations or financial results are included in Veren’s reports on file with Canadian and U.S. securities regulatory authorities. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed herein. Veren undertakes no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise, unless required to do so pursuant to applicable law. All subsequent forward-looking statements, whether written or oral, attributable to Veren or persons acting on the Company’s behalf are expressly qualified in their entirety by these cautionary statements.
Product Type Production Information
The Company’s annual aggregate production for the three months and year ended December 31, 2024 and December 31, 2023 and the references to “natural gas”, “crude oil” and “condensate” reported in this Press Release consist of the following product types, as defined in NI 51-101 and using a conversion ratio of 6 mcf : 1 bbl where applicable:
|
Three months ended December 31 |
Year ended December 31 |
|||
|
|
2023 |
|
2023 |
|
|
Light & Medium Crude Oil (bbl/d) |
|
12,198 |
|
12,665 |
|
Heavy Crude Oil (bbl/d) |
|
3,795 |
|
3,818 |
|
Tight Oil (bbl/d) |
|
56,657 |
|
49,779 |
|
Total Crude Oil (bbl/d) |
|
72,650 |
|
66,262 |
|
Condensate (bbl/d) |
|
23,494 |
|
21,825 |
|
Other (bbl/d) |
|
16,023 |
|
15,026 |
|
NGLs (bbl/d) |
|
39,517 |
|
36,851 |
|
Shale Gas (mcf/d) |
|
236,926 |
|
200,514 |
|
Conventional Natural Gas (mcf/d) |
|
11,380 |
|
10,761 |
|
Total Natural Gas (mcf/d) |
|
248,306 |
|
211,275 |
|
Total production from continuing operations (boe/d) |
|
153,551 |
|
138,326 |
|
Three months ended December 31 |
Year ended December 31 |
|||
|
|
2023 |
|
2023 |
|
|
Light & Medium Crude Oil (bbl/d) |
|
12,198 |
|
12,665 |
|
Heavy Crude Oil (bbl/d) |
|
3,795 |
|
3,818 |
|
Tight Oil (bbl/d) |
|
62,512 |
|
63,906 |
|
Total Crude Oil (bbl/d) |
|
78,505 |
|
80,389 |
|
Condensate (bbl/d) |
|
23,846 |
|
22,517 |
|
Other (bbl/d) |
|
17,527 |
|
19,017 |
|
NGLs (bbl/d) |
|
41,373 |
|
41,534 |
|
Shale Gas (mcf/d) |
|
242,965 |
|
214,165 |
|
Conventional Natural Gas (mcf/d) |
|
11,380 |
|
10,761 |
|
Total Natural Gas (mcf/d) |
|
254,345 |
|
224,926 |
|
Total average daily production (boe/d) |
|
162,269 |
|
159,411 |
Product types for January 2025 production are substantially similar to those in the three months ended December 31, 2024.
NI 51-101 includes condensate within the natural gas liquids (NGLs) product type. The Company has disclosed condensate as combined with crude oil and/or separately from other natural gas liquids in this press release since the price of condensate as compared to other natural gas liquids is currently significantly higher and the Company believes that this crude oil and condensate presentation provides a more accurate description of its operations and results therefore.
Definitions
Decline rate is the reduction in rate of production from one period to the next. This rate is usually expressed on an annual basis.
Finding and development (F&D) costs are calculated by dividing the development capital expenditures by the applicable reserves additions. F&D costs can include or exclude changes to future development capital costs.
Finding, development and acquisition (FD&A) costs are equivalent to F&D costs plus the costs of acquiring and disposing particular assets.
Future development capital (FDC) reflects the best estimate of the cost required to bring undeveloped proved and probable reserves on production. Changes in FDC can result from acquisition and disposition activities, development plans or changes in capital efficiencies due to inflation or reductions in service costs and/or improvements to drilling and completion methods.
N1 51-101 means “National Instrument 51-101 –Standards for Disclosure for Oil and Gas Activities“.
Recycle Ratio is calculated as operating netback divided by F&D or FD&A (including or excluding FDC) and is based on the netbacks reported above.
Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Proved reserves are reserves estimated to have a high degree of certainty of recoverability. Probable reserves are less certain to be recoverable than proved reserves and possible reserves are less certain than probable reserves.
Reserve Life Index is calculated as proved plus probable reserves divided by production.
Reserves and Drilling Data
The reserves information contained in this press release has been prepared in accordance with NI 51-101.
Where applicable, a barrels of oil equivalent (“boe”) conversion rate of six thousand cubic feet of natural gas to one barrel of oil equivalent (6mcf:1bbl) has been used based on an energy equivalent conversion method primarily applicable at the burner tip. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the 6:1 conversion ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value.
This press release contains metrics commonly used in the oil and natural gas industry, including “decline rate”, “F&D costs”, “FD&A costs”, “FDC”, “recycle ratio”, “replacement rate”, “reserve life index” and “netbacks”. These terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies and, therefore, should not be used to make such comparisons. Readers are cautioned as to the reliability of oil and gas metrics used in this press release.
F&D costs, including change in FDC, and FD&A costs have been presented in this news release because they provide a useful measure of capital efficiency. F&D costs and FD&A costs, including land, facility and seismic expenditures and excluding change in FDC have also been presented in this news release because they provide a useful measure of capital efficiency.
Management uses recycle ratio for its own performance measurements and to provide shareholders with measures to compare the Company’s performance over time.
Netback is calculated on a per boe basis as oil and gas sales, less royalties, operating and transportation expenses and realized derivative gains and losses. Netback is used by management to measure operating results on a per boe basis to better analyze performance against prior periods on a comparable basis.
Replacement rate is the amount of oil added to the Company’s 2P reserves, divided by production. It is a measure of the ability of the Company to sustain production levels.
Reserve Life Index is calculated as set forth above, it is a measure of the longevity of the Company’s reserves.
Decline rate is used by management to assess the longevity of production.
There are numerous uncertainties inherent in estimating quantities of crude oil, natural gas and NGL reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth above are estimates only. In general, estimates of economically recoverable crude oil, natural gas and NGL reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially. For these reasons, estimates of the economically recoverable crude oil, NGL and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary. The Company’s actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material.
Initial production is for a limited time frame only (30 days) and may not be indicative of future performance. Individual properties may not reflect the same confidence level as estimates of reserves for all properties due to the effects of aggregation. This press release contains estimates of the net present value of the Company’s future net revenue from our reserves. Such amounts do not represent the fair market value of our reserves. The recovery and reserve estimates of the Company’s reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered.
The reserve data provided in this news release presents only a portion of the disclosure required under National Instrument 51-101. All of the required information is contained in the Company’s Annual Information Form for the year ended December 31, 2024, on SEDAR+ (accessible at www.sedarplus.ca and EDGAR (accessible at www.sec.gov/edgar.shtml) and further supplemented by Material Change Reports as applicable.
FOR MORE INFORMATION ON VEREN, PLEASE CONTACT:
Sarfraz Somani
, Manager, Investor Relations
Telephone: (403) 693-0020 Toll-free (US and Canada): 888-693-0020
Address: Veren Inc. Suite 2000, 585 – 8th Avenue S.W. Calgary AB T2P 1G1
Veren shares are traded on the Toronto Stock Exchange and New York Stock Exchange under the symbol VRN.
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