Vermilion Energy Inc. press release
Vermilion Energy Inc. Announces Results for the Three and Nine Months Ended September 30, 2024
TSX - Toronto Stock Exchange · Canada
Canada NewsWire
CALGARY, AB , Nov. 6, 2024 /CNW/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX: VET) (NYSE: VET) is pleased to report operating and condensed financial results for the three and nine months ended September 30, 2024 .
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The unaudited interim financial statements and management discussion and analysis for the three and nine months ended September 30, 2024 will be available on the System for Electronic Document Analysis and Retrieval Plus ("SEDAR+") at www.sedarplus.ca , on EDGAR at www.sec.gov/edgar.shtml , and on Vermilion's website at www.vermilionenergy.com .
Highlights
Q3 2024 fund flows from operations ("FFO") (1) was $275 million ( $1.76 /basic share) (2) , representing a 16% increase over the prior quarter, primarily due to stronger European gas prices. Benchmark TTF Day Ahead pricing increased 14% over the prior quarter, averaging $15.52 /mmbtu in Q3 2024, and European gas was the only commodity in our portfolio that increased quarter-over-quarter and year-over-year. As a result of strong European gas prices, our corporate average realized natural gas price in Q3 2024 was $6.57 /mcf, compared to $0.69 /mcf for the AECO 5A benchmark. Net earnings for Q3 2024 was $52 million ( $0.33 /basic share), an increase of $134 million over the prior quarter primarily due to a more normalized mark-to-market adjustment on our hedge book. We invested $121 million in exploration and development ("E&D") capital expenditures (3) , resulting in free cash flow ("FCF") (4) of $154 million ( $0.98 /basic share) (5) , of which $59 million was returned to shareholders, including $19 million in dividends and $40 million of share buybacks, representing 45% of excess FCF ("EFCF") (4) . Year-to-date, we have returned $180 million ( $1.13 /basic share) to shareholders through dividends and share buybacks, representing 38% of EFCF, including the repurchase and cancellation of 8.0 million shares which has reduced our outstanding common shares to 155.3 million as at September 30, 2024 . We continue to repurchase shares in Q4 2024 and are on track to return 10% of our market capitalization to shareholders in 2024 between our fixed dividend and variable share repurchase program, and expect to continue providing ratable dividend increases and repurchasing shares in future periods. Net debt (6) decreased by $73 million in Q3 2024 to $833 million , representing a net debt to trailing FFO ratio (7) of 0.6 times, the lowest in 15 years. Production during Q3 2024 averaged 84,173 boe/d (8) (56% natural gas and 44% crude oil and liquids), comprised of 53,936 boe/d (8) from our North American assets and 30,237 boe/d (8) from our International assets, and includes the impact from a planned turnaround in Australia and the partial shut-in of some Canadian gas production due to weak AECO pricing. Our Q3 2024 production represents an increase of 2% year-over-year, or 7% on a per share basis, reflecting the positive impact from our share repurchase program. Notably, production from our International assets has increased 16% over the prior year, including a 26% increase in natural gas production driven by new production from our SA-10 block in Croatia and higher runtime in Ireland . In Germany , we successfully completed testing operations for our first deep gas exploration well drilled earlier this year. The well flow tested at a restricted rate of 17 mmcf/d (15) of natural gas with a wellhead pressure of 4,625 psi, which supports our expectation that deliverability would have been higher without testing equipment limitations. Tie-in operations are progressing to bring the well on production in the first half of 2025. We commenced drilling on our second deep gas exploration well (0.3 net) in August 2024 and successfully completed drilling operations at the end of October 2024 . We are pleased to report that we discovered gas within the reservoir and are now proceeding with completion and testing operations. Subsequent to the quarter, we commenced drilling on our third German deep gas exploration well (1.0 net) in October 2024 . We anticipate results from the second well test and third well drilling operations in the first half of 2025. In Croatia , we successfully increased production on the SA-10 block after commissioning the gas plant in late June 2024 . Production in Q3 2024 averaged 1,855 boe/d (100% European natural gas) and currently exceeds 2,000 boe/d. On the SA-7 block, we completed testing on the third well of our four-well program, at a reservoir depth of 885 metres, which flow tested at 5.6 mmcf/d (16) of natural gas. During Q3 2024 we achieved a major safety milestone in Ireland , where we celebrated two years and one million man-hours without a lost time incident, a testament to Vermilion's high standard for safety in our operations. In Canada , we completed and brought on production five (5.0 net) Montney liquids-rich shale gas wells during the third quarter. These wells have produced at an average IP90 rate of over 1,000 boe/d (17) per well (43% liquids) (17) , which is in line with expectations. The total drill, complete, equip and tie-in ("DCET") cost for the 9-21 pad was approximately $9.6 million per well as we continue to make progress towards our normalized targeted cost range of $9.0 to $9.5 million per well. The new battery and water infrastructure have achieved 99% run time since starting up and are contributing to these cost savings. In conjunction with our Q3 2024 release, we announced a quarterly cash dividend of $0.12 per common share, payable on January 15, 2025 to shareholders of record on December 31, 2024 . We have tightened our 2024 production guidance range to 84,000 to 85,000 boe/d to reflect increased certainty on annual production levels, and our capital budget of $600 to $625 million remains unchanged. We are in the process of finalizing our 2025 budget which will target modest production growth on a similar capital spending level as 2024, while maintaining our return of capital payout target at 50% of EFCF.
| ($M except as indicated) | Q3 2024 | Q2 2024 | Q3 2023 | YTD 2024 | YTD 2023 | | Financial | | | | | | | Petroleum and natural gas sales | 490,095 | 478,925 | 475,532 | 1,477,055 | 1,499,586 | | Cash flows from operating activities | 134,547 | 266,322 | 118,436 | 755,164 | 680,697 | | Fund flows from operations (1) | 275,024 | 236,703 | 270,218 | 943,085 | 770,494 | | Fund flows from operations ($/basic share) (2) | 1.76 | 1.48 | 1.65 | 5.93 | 4.70 | | Fund flows from operations ($/diluted share) (2) | 1.75 | 1.47 | 1.62 | 5.87 | 4.61 | | Net earnings (loss) | 51,697 | (82,425) | 57,309 | (28,423) | 565,549 | | Net earnings (loss) ($/basic share) | 0.33 | (0.52) | 0.35 | (0.18) | 3.45 | | Cash flows used in investing activities | 145,828 | 153,025 | 170,404 | 480,196 | 443,503 | | Capital expenditures (3) | 121,269 | 110,610 | 125,639 | 422,321 | 447,304 | | Acquisitions (9) | 1,642 | 5,450 | 5,238 | 16,844 | 247,294 | | Dispositions | — | — | — | — | 182,152 | | Asset retirement obligations settled | 15,332 | 11,745 | 13,582 | 32,052 | 28,029 | | Repurchase of shares | 40,106 | 46,555 | 11,645 | 123,070 | 66,102 | | Cash dividends ($/share) | 0.12 | 0.12 | 0.10 | 0.36 | 0.30 | | Dividends declared | 18,642 | 18,981 | 16,367 | 56,806 | 49,023 | | % of fund flows from operations (10) | 7 % | 8 % | 6 % | 6 % | 6 % | | Payout (12) | 155,243 | 141,336 | 155,588 | 511,179 | 524,356 | | % of fund flows from operations (11) | 56 % | 60 % | 58 % | 54 % | 68 % | | Free cash flow (4) | 153,755 | 126,093 | 144,579 | 520,764 | 323,190 | | Long-term debt | 903,354 | 915,364 | 966,505 | 903,354 | 966,505 | | Net debt (6) | 833,331 | 906,715 | 1,242,522 | 833,331 | 1,242,522 | | Net debt to four quarter trailing fund flows from operations (7) | 0.6 | 0.7 | 1.2 | 0.6 | 1.2 | | Operational | | | | | | | Production (8) | | | | | | | Crude oil and condensate (bbls/d) | 29,837 | 32,879 | 31,417 | 31,797 | 31,407 | | NGLs (bbls/d) | 7,547 | 7,196 | 7,344 | 7,264 | 7,261 | | Natural gas (mmcf/d) | 280.73 | 269.39 | 263.80 | 274.93 | 265.09 | | Total (boe/d) | 84,173 | 84,974 | 82,727 | 84,881 | 82,849 | | Average realized prices | | | | | | | Crude oil and condensate ($/bbl) | 103.55 | 108.93 | 106.94 | 105.54 | 100.64 | | NGLs ($/bbl) | 27.49 | 31.61 | 27.77 | 30.99 | 30.89 | | Natural gas ($/mcf) | 6.57 | 5.69 | 6.32 | 6.13 | 8.08 | | Production mix (% of production) | | | | | | | % priced with reference to WTI | 32 % | 32 % | 34 % | 32 % | 35 % | | % priced with reference to Dated Brent | 13 % | 15 % | 13 % | 14 % | 12 % | | % priced with reference to AECO | 33 % | 33 % | 34 % | 33 % | 34 % | | % priced with reference to TTF and NBP | 22 % | 20 % | 19 % | 21 % | 19 % | | Netbacks ($/boe) | | | | | | | Operating netback (12) | 41.89 | 40.32 | 49.30 | 48.23 | 46.42 | | Fund flows from operations ($/boe) (13) | 34.78 | 30.87 | 35.76 | 39.99 | 34.19 | | Average reference prices | | | | | | | WTI (US $/bbl) | 75.10 | 80.57 | 82.26 | 77.54 | 77.40 | | Dated Brent (US $/bbl) | 80.18 | 84.94 | 86.76 | 82.79 | 82.14 | | AECO ($/mcf) | 0.69 | 1.18 | 2.61 | 1.45 | 2.76 | | TTF ($/mcf) | 15.52 | 13.62 | 14.11 | 13.62 | 17.39 | | Share information ('000s) | | | | | | | Shares outstanding - basic | 155,348 | 158,174 | 163,666 | 155,348 | 163,666 | | Shares outstanding - diluted (14) | 158,912 | 161,672 | 167,904 | 158,912 | 167,904 | | Weighted average shares outstanding - basic | 156,624 | 159,525 | 163,946 | 159,114 | 163,848 | | Weighted average shares outstanding - diluted (14) | 157,502 | 161,069 | 166,392 | 160,743 | 167,167 |
| (1) | Fund flows from operations (FFO) is a total of segments measure comparable to net earnings (loss) that is comprised of sales less royalties, transportation, operating, G&A, corporate income tax, PRRT, windfall taxes, interest expense, equity based compensation settled in cash, realized gain (loss) on derivatives, realized foreign exchange gain (loss), and realized other income (expense). The measure is used to assess the contribution of each business unit to Vermilion's ability to generate income necessary to pay dividends, repay debt, fund asset retirement obligations, and make capital investments. FFO does not have a standardized meaning under IFRS and therefore may not be comparable to similar measures provided by other issuers. More information and a reconciliation to primary financial statement measures can be found in the "Non-GAAP and Other Specified Financial Measures" section of this document. | | | | | (2) | Fund flows from operations per share (basic and diluted) are supplementary financial measures and are not standardized financial measures under IFRS, and therefore may not be comparable to similar measures disclosed by other issuers. They are calculated using FFO (a total of segments measure) and basic/diluted shares outstanding. The measure is used to assess the contribution per share of each business unit. More information and a reconciliation to primary financial statement measures can be found in the "Non-GAAP and Other Specified Financial Measures" section of this document. | | | | | (3) | Capital expenditures is a non-GAAP financial measure that is the sum of drilling and development costs and exploration and evaluation costs from the Consolidated Statements of Cash Flows. More information and a reconciliation to primary financial statement measures can be found in the "Non-GAAP and Other Specified Financial Measures" section of this document. | | | | | (4) | Free cash flow (FCF) and excess free cash flow (EFCF) are non-GAAP financial measures comparable to cash flows from operating activities. FCF is comprised of FFO less drilling and development and exploration and evaluation expenditures and EFCF is FCF less payments on lease obligations and asset retirement obligations settled. More information and a reconciliation to primary financial statement measures can be found in the "Non-GAAP and Other Specified Financial Measures" section of this document. | | | | | (5) | Free cash flow per basic share is a non-GAAP supplementary financial measure and is not a standardized financial measure under IFRS and may not be comparable to similar measures disclosed by other issuers. It is calculated using FCF and basic shares outstanding. | | | | | (6) | Net debt is a capital management measure most directly comparable to long-term debt and is comprised of long-term debt (excluding unrealized foreign exchange on swapped USD borrowings) plus adjusted working capital (defined as current assets less current liabilities, excluding current derivatives and current lease liabilities). More information and a reconciliation to primary financial statement measures can be found in the "Non-GAAP and Other Specified Financial Measures" section of this document. | | | | | (7) | Net debt to four quarter trailing fund flows from operations is a supplementary financial measure and is not a standardized financial measure under IFRS. It may not be comparable to similar measures disclosed by other issuers and is calculated using net debt (capital management measure) and FFO (total of segment measure). The measure is used to assess the ability to repay debt. Information in this document is included by reference; refer to the "Non-GAAP and Other Specified Financial Measures" section of this document. | | | | | (8) | Please refer to Supplemental Table 4 "Production" of the accompanying Management's Discussion and Analysis for disclosure by product type. | | | | | (9) | Acquisitions is a non-GAAP financial measure that is calculated as the sum of acquisitions, net of cash acquired, and acquisitions of securities from the Consolidated Statements of Cash Flows, Vermilion common shares issued as consideration, the estimated value of contingent consideration, the amount of acquiree's outstanding long-term debt assumed, and net acquired working capital. More information and a reconciliation to primary financial statement measures can be found in the "Non-GAAP and Other Specified Financial Measures" section of this document. | | | | | (10) | Dividends % of FFO is a supplementary financial measure that is not standardized under IFRS and may not be comparable to similar measures disclosed by other issuers. Dividends % of FFO is calculated as dividends declared divided by FFO. The ratio is used by management as a metric to assess the cash distributed to shareholders. | | | | | (11) | Payout and payout % of FFO are a non-GAAP financial measure and a non-GAAP ratio, respectively, that are not standardized under IFRS and may not be comparable to similar measures disclosed by other issuers. Payout is comparable to dividends declared and is comprised of dividends declared plus drilling and development costs, exploration and evaluation costs, and asset retirement obligations settled, while the ratio is calculated as payout divided by FFO. More information and a reconciliation to primary financial statement measures can be found in the "Non-GAAP and Other Specified Financial Measures" section of this document. | | | | | (12) | Operating netback is a non-GAAP financial measure comparable to net earnings and is comprised of sales less royalties, operating expense, transportation costs, PRRT, and realized hedging gains and losses. More information and a reconciliation to primary financial statement measures can be found in the "Non-GAAP and Other Specified Financial Measures" section of this document. | | | | | (13) | Fund flows from operations per boe is a supplementary financial measure that is not standardized under IFRS and may not be comparable to similar measures disclosed by other issuers, calculated as FFO by boe production. Fund flows from operations per boe is used by management to assess the profitability of our business units and Vermilion as a whole. More information and a reconciliation to primary financial statement measures can be found in the "Non-GAAP and Other Specified Financial Measures" section of this document. | | | | | (14) | Diluted shares outstanding represent the sum of shares outstanding at the period end plus outstanding awards under the Long-term Incentive Plan ("LTIP"), based on current estimates of future performance factors and forfeiture rates. | | | | | (15) | Osterheide Z2-2 well (100% working interest) tested at a rate of 17.3 mmcf/d during an eight-hour flow period with flowing wellhead pressure of 4,625 psi during initial well cleanup on an adjustable choke. The completion fluid was recovered during the clean-up flow period. A final shut-in wellhead pressure of 5,757 psi and bottom hole pressure of 7,235 psi were recorded following the well test. The tested zone is the Rotliegend Wustrow formation which was encountered at 5,757m measured depth ("MD") and a 42.0 m gas column was logged with 13.8 m of net reservoir and average effective porosity of 8.3%. Test results are not necessarily indicative of long-term performance or ultimate recovery. | | | | | (16) | Gojlo-1 Jug well (60% working interest) tested at rate of 5.6 mmcf/d and flowing wellhead pressure of 692 psi during a well cleanup on a 0.5938'' diameter choke. The well was shut-in and then flow tested for 24 hours on 3 choke sizes (0.25", 0.3125", 0.375") to obtain necessary reservoir data and to minimize flaring. Gojlo-1Jug well tested 8.5 hours at an average rate of 2.9 mmcf/d with a flowing wellhead pressure of 861 psi on a 0.375'' diameter choke. Load fluid was recovered, and no formation water was produced during the test. A final shut-in wellhead pressure of 1,009 psi and bottom hole pressure of 1,070 psi were recorded following the well test. The tested zone was the Mramor Brdo formation which was encountered at 885m MD and a 17.6m gas column was logged in the well to the base of the reservoir with 15.6m of net reservoir and an average porosity of 31%. Test results are not necessarily indicative of long-term performance or ultimate recovery. | | | | | (17) | Initial 90-day production ("IP90") for the Company's most recent five (5.0 net) wells drilled on our British Columbia lands averaged 1,000 boe/d per well. IP90 consisted of 34% tight oil, 9% NGLs, and 57% shale gas, using a conversion of six mcf of gas to one barrel of oil, based on field level estimates for the first 90 full days of production following the tie-in of the well. Production rates presented are for a limited timeframe only and may not be indicative of future performance or the ultimate recovery for a given well or pad. |
Message to Shareholders
The third quarter of 2024 highlighted the strength of our diversified portfolio and the compounding impact of our share buyback program. Production during the third quarter averaged 84,173 boe/d (1) including the impact from a planned turnaround in Australia and the partial shut-in of some Canadian gas production due to weak AECO pricing. Our Q3 2024 production represents an increase of 2% year-over-year, or 7% on a per share basis reflecting the positive impact from our share repurchase program. We generated $275 million of fund flows from operations ("FFO") during the third quarter, representing a 16% increase over the prior quarter, primarily due to stronger European gas prices. Benchmark TTF Day Ahead pricing increased 14% over the prior quarter, averaging $15.52 /mmbtu in Q3 2024, and European gas was the only commodity in our portfolio that increased quarter-over-quarter and year-over-year. European natural gas comprises 40% of our natural gas production and 22% of our total corporate production. The forward price for European natural gas benchmarks, TTF and NBP, remain strong, with 2025 forward pricing over $17 /mmcf, or approximately eight times higher than AECO. This pricing dynamic supports strong cash flow and netbacks across our European business units, with 2024 operating netbacks of approximately $60 /boe (4) from our European natural gas operations.