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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 OF THE SECURITIES EXCHANGE ACT OF 1934 For the month of February 2025
Commission File Number 1-32895 ___________________ Obsidian Energy Ltd. (Translation of registrant's name into English) Suite 200, 207 – 9th Avenue SW
Calgary, Alberta T2P 1K3 Canada (Address of principal executive offices) ___________________ Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F. Form 20-F ☐ 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) ☐ . |
DOCUMENTS INCLUDED AS PART OF THIS FORM 6-K
See the Exhibit Index hereto.
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, on February 25, 2025.
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OBSIDIAN ENERGY LTD. |
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By: |
/s/ Stephen Loukas |
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Name: |
Stephen Loukas |
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Title: |
President and Chief Executive Officer |
EXHIBIT INDEX
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Exhibit |
Description |
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99.1 |
News release, dated February 25, 2025 |
99.2 |
News release, dated February 25, 2025 |
Exhibit 99.1
Obsidian Energy Announces Fourth Quarter and Full Year 2024 Results
•Generated $432.0 million of funds flow from operations,
representing a 14 percent increase over 2023 (22 percent on a per share basis)
•Average 2024 production increased 16 percent to 37,474 boe/d over 2023
•Repurchased and cancelled six percent of shares outstanding for $41.7 million in 2024
• 2024 capital program increased production, reserves, and funds flow from operations, and added both Clearwater and Bluesky locations to support Peace River growth
CALGARY, February 25, 2025 - OBSIDIAN ENERGY LTD. (TSX / NYSE American – OBE) (“Obsidian Energy”, the “Company”, “we”, “us” or “our”) is pleased to report our operating and financial results for the fourth quarter and full year of 2024.
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Three months ended
December 31 |
Year ended December 31 |
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2024 |
2023 |
2024 |
2023 |
FINANCIAL1 (millions, except per share amounts) |
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Cash flow from operating activities |
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115.0 |
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117.7 |
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361.9 |
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352.7 |
Basic per share ($/share)2 |
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1.55 |
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1.49 |
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4.76 |
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4.36 |
Diluted per share ($/share)2 |
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1.49 |
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1.44 |
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4.57 |
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4.19 |
Funds flow from operations3 |
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107.7 |
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97.0 |
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432.0 |
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377.6 |
Basic per share ($/share)4 |
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1.45 |
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1.23 |
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5.69 |
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4.67 |
Diluted per share ($/share)4 |
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1.39 |
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1.18 |
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5.46 |
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4.49 |
Net income (loss) |
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(284.8) |
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34.3 |
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(202.6) |
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108.0 |
Basic per share ($/share) |
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(3.83) |
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0.44 |
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(2.67) |
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1.33 |
Diluted per share ($/share) |
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(3.83) |
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0.42 |
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(2.67) |
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1.28 |
Capital expenditures |
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84.1 |
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100.0 |
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343.1 |
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292.5 |
Property acquisitions (dispositions), net |
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(1.5) |
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- |
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83.4 |
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0.6 |
Decommissioning expenditures |
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3.5 |
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7.7 |
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23.9 |
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26.6 |
Long-term debt |
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335.4 |
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220.0 |
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335.4 |
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220.0 |
Net debt3 |
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411.7 |
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330.2 |
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411.7 |
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330.2 |
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OPERATIONS |
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Daily Production |
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Light oil (bbl/d) |
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13,271 |
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12,176 |
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13,463 |
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12,485 |
Heavy oil (bbl/d) |
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11,621 |
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5,851 |
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9,016 |
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5,927 |
NGL (bbl/d) |
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3,176 |
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2,614 |
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3,077 |
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2,608 |
Natural gas (mmcf/d) |
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72 |
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68 |
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72 |
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68 |
Total production5 (boe/d) |
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40,119 |
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31,974 |
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37,474 |
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32,275 |
Average sales price2,6 |
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Light oil ($/bbl) |
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96.95 |
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100.38 |
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99.95 |
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102.11 |
Heavy oil ($/bbl) |
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67.70 |
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58.53 |
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70.46 |
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61.46 |
NGLs ($/bbl) |
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44.27 |
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55.65 |
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48.05 |
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53.83 |
Natural gas ($/mcf) |
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1.53 |
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2.63 |
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1.52 |
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2.98 |
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Netback ($/boe) |
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Sales price |
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57.94 |
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59.08 |
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59.70 |
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61.37 |
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Risk management gain |
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1.62 |
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2.27 |
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1.58 |
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1.50 |
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Net sales price |
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59.56 |
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61.35 |
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61.28 |
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62.87 |
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Royalties |
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(7.85) |
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(8.52) |
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(7.76) |
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(8.30) |
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Net operating costs4 |
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(13.91) |
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(13.66) |
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(13.85) |
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(14.21) |
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Transportation |
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(4.55) |
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(3.67) |
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(4.22) |
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(3.48) |
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Netback4 ($/boe) |
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33.25 |
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35.50 |
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35.45 |
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36.88 |
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(1)We adhere to generally accepted accounting principles (“GAAP”); however, we also employ certain non-GAAP measures to analyze financial performance, financial position, and cash flow, including funds flow from operations (“FFO”), net debt, netback and net operating costs. Additionally, other financial measures are also used to analyze performance. These non-GAAP and other financial measures do not have any standardized meaning prescribed by International Financial Reporting Standards (“IFRS”) and therefore may not be comparable to similar measures provided by other issuers. Readers should not consider non-GAAP and other financial measures to be more meaningful than GAAP measures, which are determined in accordance with IFRS, such as net income and cash flow from operating activities, as indicators of our performance.
(2)Supplementary financial measure. See ‘Non-GAAP and Other Financial Measures’.
(3)Non-GAAP financial measure. See ’Non-GAAP and Other Financial Measures’.
(4)Non-GAAP ratio. See ’Non-GAAP and Other Financial Measures’.
(5)Please refer to the ’Oil and Gas Information Advisory’ section below for information regarding the term "boe".
(6)Before realized risk management gains/(losses).
Detailed information can be found in Obsidian Energy's consolidated financial statements and management's discussion and analysis ("MD&A") as at and for the year ended December 31, 2024, on our website at www.obsidianenergy.com, which will also be filed on SEDAR+ and EDGAR in due course.
2024 overview
Obsidian Energy continued to successfully implement our growth plan in 2024, increasing average annual production by 16 percent to 37,474 boe/d from 32,275 boe/d in 2023 and surpassing the top end of our previously increased guidance range. Due to the Company's active capital program and strong drilling results over the year, we achieved average production of 40,119 boe/d in the fourth quarter, of which our Peace River area comprised 12,280 boe/d. As a result of our larger $343.1 million capital program in 2024 combined with our Peace River acquisition in June (the “Peace River Clearwater Acquisition”), we achieved volume and value increases across all our reserve categories. FFO increased 14 percent to $432.0 million in 2024 over 2023 due to the strong results from our active capital program that led to higher production levels and revenues. This impact was partially offset by weaker commodity prices in 2024 with oil prices averaging WTI US$75.72 per barrel (2023: US$77.62 per barrel), and natural gas prices averaging $1.36 per GJ (2023: $2.14 per GJ).
In addition, we remained active on our share buyback program through our normal course issuer bid (“NCIB”) in 2024, repurchasing and cancelling 4.5 million of shares outstanding for $41.7 million in our efforts to return capital to shareholders. The Company is currently in the process of renewing our NCIB when it expires at the end of February.
2024 fourth Quarter and full year Corporate Highlights
•Increased Funds Flow – The Company generated FFO of $432.0 million ($5.69 per share basic) compared to $377.6 million ($4.67 per share basic) in the prior year. Fourth quarter 2024 FFO totaled $107.7 million ($1.45 per basic share) compared to $97.0 million ($1.23 per basic share) in the fourth quarter of 2023. Higher revenues from increased production levels and realized hedging gains resulted in higher FFO in both 2024 periods, which was partially offset by lower commodity prices.
•Capital Development Resulted in Production Growth – Our 2024 capital program focused on growing production through the development and further delineation of our Peace River asset as we maintained production in our light oil assets, generating significant free cash flow. Capital expenditures totalled $343.1 million (2023: $292.5 million), while decommissioning expenditures totaled $23.9 million (2023: $26.6 million). Fourth quarter capital expenditures were $84.1 million (2023: $100.0 million) and decommissioning expenditures were $3.5 million (2023: $7.7 million).
oWe also made net property acquisitions of $83.4 million in 2024 (2023: $0.6 million), the majority of which was used for the Peace River Clearwater Acquisition to purchase additional Clearwater production, reserves and land.
•Active Share Buyback Program – A total of approximately 4.5 million shares were repurchased and cancelled under the Company’s NCIB for $41.7 million (at an average price of $9.30 per share) in 2024. Of this amount, 1.6 million shares were repurchased and cancelled in the fourth quarter for $13.2 million ($8.17 per share).
oIn total, we repurchased and cancelled approximately 9.6 million shares at an average price of $9.31 per share for $89.1 million under our NCIB from inception in 2023 to date. With current shares outstanding of 73,684,802, we are currently in the process of renewing our NCIB once it expires at the end of February.
•Reduced Operating Costs – Net operating costs were lower at $13.85 per boe in 2024 (2023: $14.21 per boe) and $13.91 per boe for the fourth quarter of 2024 (2023: $13.66 per boe) as the Company benefited from our higher production base and lower power prices. On an absolute basis, net operating costs increased on both an annual and quarterly basis in 2024 due to the impact of the larger production base and increased trucking costs from our expanded Peace River operations.
•Lower G&A Costs – General and administrative (“G&A”) costs decreased by seven percent to $1.50 per boe in 2024 compared to $1.61 per boe in 2023, and by eight percent to $1.39 per boe in the fourth quarter of 2024 compared to $1.51 per boe for the same quarter in 2023. Our higher production base more than offset increased staffing levels required to execute our growth plan, which led to the decrease on a per boe basis.
•Net Debt – Net debt levels increased to $411.7 million at December 31, 2024, compared to $330.2 million at December 31, 2023. The increase in 2024 was mainly due to the $80.5 million funding of our Peace River Clearwater Acquisition.
•Net Income – The Company recorded a net loss of $202.6 million ($2.67 per share basic) in 2024 compared to net income of $108.0 million ($1.33 per share basic) in 2023. The net loss in 2024 is due to the classification of our Pembina assets as held for sale at December 31, 2024 (see ‘Announced Pembina Asset Transaction’), which led to a non-cash impairment charge as we valued the assets at the expected transaction proceeds. This was partially offset by the Company's higher revenues from increased production. Excluding the after-tax non-cash impairment, the Company would have recorded net income of $101.9 million ($1.34 per share basic).
2024 fourth QUARTER and full year CAPITAL program & HIGHLIGHTS
Obsidian Energy focused on the execution of our growth plan with an active 2024 capital program that continued to illustrate the value of our assets. Weighted toward our Peace River heavy oil assets, the program expanded development in new and existing fields to increase production, while continuing to delineate and assess the potential of our large land base through exploration/appraisal drilling in both our Clearwater and Bluesky plays. At the same time, we continued to invest in our Willesden Green/Pembina (Cardium) light oil assets, resulting in stable production and continued free cash flow generation. During the fourth quarter of 2024, we focused on accelerated development at both our Peace River Bluesky and Clearwater development fields while simultaneously expanding our portfolio with the drilling of an initial delineation well targeting the Belly River formation in Willesden Green. In December, we shifted a portion of our 2025 development program into 2024 due to favourable weather conditions. Capital program highlights for 2024 are as follows:
•Increased Reserves through Strong Asset Performance – We achieved strong 2024 reserve results with volume increases across all categories, replacing production, adding new locations, and improved efficiency of our capital program.
oWe replaced 148 percent of 2024 production on a proved developed producing (“PDP”) basis, 229 percent on a total proved (“1P”) basis and 296 percent on a total proved plus probable (“2P”) basis.
▪The impact of drilling infill wells and field extensions from our 2024 capital program, the Peace River Clearwater Acquisition lands, and positive technical revisions were the major contributing factors to increased reserves.
oReserves before-tax net present value discounted at 10 percent (“NPV10”) increased from 2023 levels (largely due to the volume increases outlined above) to $1.6 billion (15 percent increase on a per share basis), $2.3 billion (23 percent increase on a per share basis) and $3.1 billion (26 percent increase on a per share basis) for PDP, 1P and 2P, respectively.
oExecution of our capital program resulted in improvements from between seven to 14 percent in both Finding and Development (“F&D”) and Finding, Development and Acquisition (“FD&A”) costs year-over-year for 1P and 2P reserves, highlighting the quality of our reserve book and ability to efficiently develop our reserves.
oOur total undeveloped 2P reserve locations increased by 114 net locations to 458 total net locations booked: including 243 net locations in the Cardium, 97 net locations in the Clearwater, 63 net locations in the Bluesky, 50 net locations in the Viking, three net locations in the Mannville and two net locations in the Belly River.
▪Peace River heavy oil locations more than tripled due to the success of our 2024 capital program combined with the impact of the 2024 Peace River Clearwater Acquisition, adding 107 net 2P reserve locations over the year.
▪These locations were booked with an achievable total 2P five-year future development capital (“FDC”) of $1.7 billion (approximately $340 million per year).
•Achieved Successful Capital Program – Our 2024 capital program, focused on our heavy oil assets, realized success in more than replacing production with new reserve additions, opening new development areas and attaining strong initial production (“IP”) rates above our internal expectations. Highlights included:
oOperated Wells Rig Released and On Production – We rig released a total of 66 (65.4 net) wells and brought 65 (64.3 net) wells on production by the end of 2024, contributing to reserve additions and production growth (see ‘2024 Wells Rig Released and On Production’).
oPeace River (Clearwater) Heavy Oil: Solid results from our Clearwater program led to substantial production growth and the addition of 86 net new 2P booked inventory locations in 2024. Development at our Dawson field continued to provide high production rates, proving the potential of our acreage and identifying new locations for future drilling. A step out to the existing field, our successful exploration/appraisal wells at West Dawson established a new high quality Clearwater oil development field for future development. We also began activity on the lands acquired in 2024 with our first development wells on the Peavine Metis Settlement area and our first exploration/appraisal well on the Gift Lake Metis Settlements lands acquired in 2024.
oPeace River (Bluesky) Heavy Oil: New development drilling at Harmon Valley South (“HVS”) successfully tested new drilling and facility designs while providing production results at the top end of our expectations with wells achieving 30-day IP rates in the range of 450 to 500 boe/d/well. Key to future development was the drilling of wells at the HVS 8-28 Pad at the southern end of the field, which has the potential to extend the field and add significant new future development locations. We also completed development and delineation drilling to further appraise our Walrus and Cadotte fields; results from these wells will be used to refine development programs and unlock future potential in these areas.
oWillesden Green Light Oil – With solid results across our Cardium development in 2024, the second well on our Open Creek 9-17 Pad surpassed expectations with an IP 30-day rate of 401 (262 net) boe/d, leading to future follow-up locations and area development. We also drilled our initial delineation well targeting the Belly River formation, which had a 30-day IP rate of 100 boe/d (77 percent oil). The well has displayed continuous improvement with increasing production rates as water levels drop, resulting in average production of 221 boe/d (76 percent
oil) over the last 25 days. Well performance will continue to be monitored as we have follow up location ready for drilling in the second half of the year.
oPembina (Cardium) Light Oil: We achieved positive results from our development drilling activities over the year, particularly during the second half with 30-day IP rates ranging from approximately 230 to 648 boe/d/well.
•Expanded Peace River Land, Production and Reserves – The Company acquired approximately 1,700 boe/d (100 percent oil, based on April 2024 production) of Clearwater production, 148 net sections of land and 6.3 Mmboe of 2P reserves (as at December 31, 2023) through the Peace River Clearwater Acquisition. The Peavine acreage is on trend with our successful Clearwater Dawson development.
•Active Decommissioning Program – We successfully abandoned a combined total of 59 net wells and 391 net kilometres of pipeline in 2024 as part of activities from our decommissioning spend of $23.9 million.
Highlights SUBSEQUENT TO 2024
•Announced Pembina Asset Transaction – In February 2025, the Company entered into a definitive asset purchase and sale agreement with Calgary-based InPlay Oil Corp. (“InPlay”) (TSX – IPO) to divest our operated Pembina (Cardium) assets (the “Pembina Assets”), while retaining our non-operated holdings in the Pembina Cardium Unit #11 (“PCU#11”).
oThe Company will receive approximately $320 million from InPlay in three components (collectively, the “Transaction”), subject to closing and other adjustments, as follows:
▪$220 million in cash (the “Cash Proceeds”);
▪$85 million of InPlay’s common shares (the “InPlay Shares”); and
▪InPlay’s 34.6 percent interest in the Willesden Green Cardium Unit #2 oil field, bringing Obsidian Energy’s ownership in the field to 99.8 percent. The additional interest is estimated to be valued at $15 million.
oThe Cash Proceeds are expected to be used to initially pay down debt, improving Obsidian Energy’s balance sheet and overall liquidity. In the second half of 2025, the Company will evaluate various opportunities to realize additional value from the InPlay Shares for Obsidian Energy’s shareholders.
2024 GUIDANCE AND RESULTS
Obsidian Energy continued to emphasize operational execution, focus on cost reduction initiatives and monitor our operations and development plans in 2024, adjusting as appropriate given volatility in commodity markets. As a result, all operational metrics met or surpassed our 2024 guidance, including production, net operating costs and G&A. Favourable weather conditions in December led to the Company accelerating development activity anticipated for 2025 into late 2024, modestly increasing capital expenditures above guidance. Net operating costs and G&A were at the low end or lower than our guidance ranges due to our strong production growth and focus on cost savings initiatives.
Higher production volumes resulted in higher production revenues, helping to offset the lower commodity prices in 2024 compared to 2023 and leading to FFO and FCF that was above our 2024 guidance levels and 2023 results. Net debt and leverage ratios were above forecasts largely due to the funding of the complimentary Peace River Clearwater Acquisition that provided production and additional drilling locations to further support our growth strategy in the area.
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2024E Guidance |
2024 Results |
Production1 |
boe/d |
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37,000 – 37,400 |
37,474 |
% Oil and NGLs |
% |
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69% |
68% |
Capital expenditures2 |
$ millions |
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320 – 335 |
343.1 |
Acquisition expenditures3 |
$ millions |
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85 |
83.4 |
Decommissioning expenditures |
$ millions |
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23 – 24 |
23.9 |
Net operating costs4 |
$/boe |
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13.75 – 14.25 |
13.85 |
General & administrative |
$/boe |
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1.55 – 1.65 |
1.50 |
Based on midpoint of above guidance |
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WTI5 |
US$/bbl |
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72.50 |
75.72 |
MSW Differential5 |
US$/bbl |
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3.50 |
4.51 |
WCS Differential5 |
US$/bbl |
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15.00 |
14.73 |
AECO5 |
CAD$/GJ |
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1.50 |
1.36 |
FFO4. 6 |
$ millions |
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420 |
432 |
FFO per share (basic)4, 7 |
$/share |
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5.51 |
5.69 |
FCF4,6 |
$ millions |
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69 |
65 |
FCF/share4, 7 |
$/share |
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0.90 |
0.86 |
Net debt8 |
$ millions |
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390 |
412 |
Net debt to FFO8 |
times |
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0.9 |
1.0 |
(1)Approximate mid-point of 2024E guidance range was 13,500 bbl/d light oil, 8,900 bbl/d heavy oil, 3,000 bbl/d NGLs and 70.6 mmcf/d natural gas with a minimal amount of forecasted production associated with exploration/appraisal capital expenditures. Actual 2024 production was composed of 13,463 bbl/d light oil, 9,016 bbl/d heavy oil, 3,077 bbl/d NGLs and 71.5 mmcf/d natural gas.
(2)2024E capital expenditures included approximately $21 million for Peace River exploration/appraisal activity with minimal impact on forecasted production volumes. Actual 2024 capital expenditures included $27 million for exploration/appraisal activity, including cost related to accelerating 2025 activity into late 2024.
(3)Guidance 2024E capital expenditures included approximately $4 million for minor acquisitions in 2024. Actual acquisition expenditures include $81 million for the Peace River Clearwater Acquisition and approximately $3 million for other minor acquisitions completed in 2024.
(4)Non-GAAP financial measure or ratio. See ’Non-GAAP and Other Financial Measures’.
(5)WTI and AECO pricing assumptions of 2024E guidance were forecasted for October to December 31, 2024, while MSW and WCS differentials were forecasted for November to December 2024. Pricing assumptions included risk management (hedging) adjustments as of September 30, 2024. Full year 20224 pricing resulted in WTI of US$75.72/bbl, MSW differentials of US$4.60/bbl, WCS differentials of US$14.75/bbl, AECO of $1.46/GJ, and FX of 1.37x CAD/USD.
(6)2024E guidance FFO and FCF included approximately $2 million of estimated charges for full year 2024 related to the deferred share units, performance share units and non-treasury incentive plan cash compensation amounts which were based on a share price of $7.99 per share. Actual 2024 FFO and FCF included, in aggregate, no charge related to the deferred share units, performance share units and non-treasury incentive plan cash compensation amounts, which were based on a share price of $8.36 per share.
(7)2024E guidance per share calculations were based on an estimated 76.3 million weighted average shares outstanding for the 12-months ended December 31, 2024. Actual 2024 per share calculations were based on 76.0 million weighted average shares outstanding for the 12-months ended December 31, 2024.
(8)2024E guidance net debt figures included the impact of approximately $29 million of share purchases to September 30, 2024, under the Company’s NCIB program. Actual 2024 net debt included the impact of $42 million of share purchases under the Company’s NCIB program.
2024 WELLS RIG RELEASED AND ON PRODUCTION
Obsidian Energy completed our fourth quarter 2024 drilling program with four rigs in operation – three drilling rigs in our Peace River area and one in our Willesden Green area. With a high activity level throughout the year and an accelerated drilling program in the fourth quarter of 2024, a total of 66 (65.4 net) operated wells were rig released (including five oilsands exploration (“OSE”) wells) and 65 (64.3 net) operated wells were brought on production by the end of 2024 (including seven (7.0 net) wells from our 2023 program). The remaining three (3.0 net) wells rig released in 2024 were placed on production in January 2025. The breakdown of our operated capital program is as follows:
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Total Gross (Net) Wells
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Operated Wells
Rig Released |
Operated Wells
On Production |
Heavy Oil Assets |
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Peace River (Bluesky) |
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24 (24.0) |
22 (22.0) |
Peace River (Clearwater) |
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13 (13.0) |
13 (13.0) |
Light Oil Assets |
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Willesden Green (Cardium/Belly River) |
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9 (8.7) |
12 (11.7) |
Pembina (Cardium) |
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10 (9.7) |
13 (12.6) |
Viking |
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- |
- |
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56 (55.4) |
60 (59.3) |
EXPLORATION/APPRAISAL WELLS |
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Peace River (Clearwater) |
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5 (5.0) |
5 (5.0) |
Peace River (OSE) |
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5 (5.0) |
- |
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10 (10.0) |
5 (5.0) |
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TOTAL OPERATED WELLS |
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66 (65.4) |
65 (64.3) |
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(1)Wells on production in 2024 include seven (7.0 net) wells rig released in 2023 that came on production in the first quarter of 2024. In total, 65 (64.3 net) wells were on production by the end of 2024. (2)In addition, Obsidian Energy participated in the rig release of 18 non-operated (6.3 net) wells in 2024, two (0.9 net) of which were water injection wells. |
HEDGING UPDATE
In 2024, the Company had an active hedging program and entered into various oil and natural gas contracts, leading to a realized gain of $21.6 million during the year, primarily related to our natural gas contracts. The following contracts are in place for 2025 on a weighted average basis:
Oil Contracts
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Type |
Remaining
Term |
Volume
(bbl/d) |
Swap
Price (C$/bbl) |
WTI Swaps |
January 2025 |
14,250 |
$100.46 |
WTI Swaps |
February 2025 |
13,071 |
$103.45 |
WTI Swaps |
March 2025 |
11,250 |
$106.37 |
WTI Swaps |
April 2025 |
500 |
$102.20 |
WCS Differential |
Jan. – March, July – Dec. 2025 |
6,000 |
($19.30) |
WCS Differential |
April – June 2025 |
8,500 |
($19.39) |
MSW Differential |
April – June 2025 |
1,250 |
($7.99) |
AECO Natural Gas Contracts
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Type |
Remaining
Term |
Volume
(mcf/d) |
|
Swap Price (C$/mcf) |
AECO Swap |
January – March 2025 |
|
14,929 |
|
$3.74 |
AECO Swap |
April – October 2025 |
|
11,374 |
|
$2.24 |
AECO Collars |
January – March 2025 |
|
4,976 |
|
$3.43 - $4.11 |
AECO Collars |
April – October 2025 |
|
1,896 |
|
$2.11 - $2.64 |
UPDATED CORPORATE PRESENTATION
For further information on these and other matters, Obsidian Energy will post an updated corporate presentation on our website, www.obsidianenergy.com, in due course.
SCOTIABANK GLOBAL ENERGY CONFERENCE
Obsidian Energy will be participating in the 53rd Annual Scotiabank Global Energy Conference in Miami, Florida at the Mandarin Oriental Hotel. Stephen Loukas, President and Chief Executive Officer, along with Peter Scott, Senior Vice President and Chief Financial Officer will be hosting one-on-one meetings on February 26 and 27, 2025 at the conference centre.
ADDITIONAL READER ADVISORIES
OIL AND GAS INFORMATION ADVISORY
Barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of crude 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. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is misleading as an indication of value.
In addition, this news release contains several oil and gas metrics, including "F&D”, “FD&A” and “FDC", which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies. Such metrics are commonly used in the oil and gas industry and have been included herein to provide readers with additional measures to evaluate the Company's performance; however, such measures are not reliable indicators of the future performance of the Company and future performance may not compare to the performance in previous periods.
F&D costs are the sum of capital expenditures incurred in the period, plus the change in estimated future development capital for the reserves category, all divided by the change in reserves during the period for the reserve category. F&D costs exclude the impact of acquisitions and divestitures.
FD&A costs are the sum of capital expenditures incurred in the period for the reserves category and include the impact of acquisition and disposition activity, all divided by the change in reserves during the period for the reserve category.
FDC stands for future development capital and are the estimated exploration and development costs to develop and produce reserves. Future development capital excludes capitalized administration costs.
Under NI 51-101, 1P reserves estimates are defined as having a high degree of certainty to be recoverable with a targeted 90 percent probability in aggregate that actual reserves recovered over time will equal or exceed proved reserve estimates. For 2P reserves, the targeted probability under NI 51-101 is an equal (50 percent) likelihood that the actual reserves to be recovered will be greater or less than the proved plus probable reserve estimate. The reserve estimates set forth above are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein.
TEST RESULTS AND INITIAL PRODUCTION RATES
Test results and initial production rates disclosed herein, particularly those short in duration, may not necessarily be indicative of long-term performance or of ultimate recovery. Readers are cautioned that short-term rates should not be relied upon as indicators of future performance of these wells and therefore should not be relied upon for investment or other purposes. A pressure transient analysis or well-test interpretation has not been carried out and thus certain of the test results provided herein should be considered preliminary until such analysis or interpretation has been completed.
DRILLING LOCATIONS
This news release discloses drilling locations or inventory. Unbooked drilling locations are internal estimates based on our prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources.
Unbooked locations have been identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that we will drill all unbooked locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been de-risked by drilling existing wells in relative close proximity to such unbooked drilling locations, other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves or production.
NON-GAAP AND OTHER FINANCIAL MEASURES
Throughout this news release and in other materials disclosed by the Company, we employ certain measures to analyze financial performance, financial position, and cash flow. These non-GAAP and other financial measures do not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures provided by other issuers. The non-GAAP and other financial measures should not be considered to be more meaningful than GAAP measures which are determined in accordance with IFRS, such as net income and cash flow from operating activities as indicators of our performance. The Company's audited annual consolidated financial statements and MD&A as at and for year ended December 31, 2024, will be available in due course on the Company's website at www.obsidianenergy.com and under our SEDAR+ profile at www.sedarplus.ca and EDGAR profile at www.sec.gov. The disclosure under the section ’Non-GAAP and Other Financial Measures’ in the MD&A is incorporated by reference into this news release.
Non-GAAP Financial Measures
The following measures are non-GAAP financial measures: FFO; net debt; net operating costs; netback; and free cash flow (“FCF”). These non-GAAP financial measures are not standardized financial measures under IFRS and might not be comparable to similar financial measures disclosed by other issuers. See the disclosure under the section ’Non-GAAP and Other Financial Measures’ in our MD&A for the year ended December 31, 2024, for an explanation of the composition of these measures, how these measures provide useful information to an investor, and the additional purposes, if any, for which management uses these measures.
For a reconciliation of FFO to cash flow from operating activities, being our nearest measure prescribed by IFRS, see ’Non-GAAP Measures Reconciliations’ below.
For a reconciliation of net debt to long-term debt, being our nearest measure prescribed by IFRS, see ’Non-GAAP Measures Reconciliations’ below.
For a reconciliation of net operating costs to operating costs, being our nearest measure prescribed by IFRS, see ’Non-GAAP Measures Reconciliations’ below.
For a reconciliation of netback to sales price, being our nearest measure prescribed by IFRS, see ’Non-GAAP Measures Reconciliations’ below.
For a reconciliation of FCF to cash flow from operating activities, being our nearest measure prescribed by IFRS, see ’Non-GAAP Measures Reconciliations’ below.
Non-GAAP Ratios
The following measures are non-GAAP ratios: FFO (basic per share ($/share) and diluted per share ($/share)), which use FFO as a component; net operating costs ($/boe), which uses net operating costs as a component; netback ($/boe), which uses netback as a component; and net debt to FFO, which uses net debt and FFO as components. These non-GAAP ratios are not standardized financial measures under IFRS and might not be comparable to similar financial measures disclosed by other issuers. See the disclosure under the section ’Non-GAAP and Other Financial Measures’ in our MD&A for the year ended December 31, 2024, for an explanation of the composition of these non-GAAP ratios, how these non-GAAP ratios provide useful information to an investor, and the additional purposes, if any, for which management uses these non-GAAP ratios.
Supplementary Financial Measures
The following measures are supplementary financial measures: average sales price; cash flow from operating activities (basic per share and diluted per share); and G&A costs ($/boe). See the disclosure under the section ’Non-GAAP and Other Financial Measures’ in our MD&A for the year ended December 31, 2024, for an explanation of the composition of these measures.
Non-GAAP Measures Reconciliations
Cash Flow from Operating Activities, FFO and FCF
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
December 31 |
|
|
Year ended
December 31 |
|
(millions) |
|
2024 |
|
|
2023 |
|
|
2024 |
|
|
2023 |
|
Cash flow from operating activities |
|
$ |
115.0 |
|
|
$ |
117.7 |
|
|
$ |
361.9 |
|
|
$ |
352.7 |
|
Change in non-cash working capital |
|
|
(13.5 |
) |
|
|
(30.3 |
) |
|
|
35.7 |
|
|
|
(13.6 |
) |
Decommissioning expenditures |
|
|
3.5 |
|
|
|
7.7 |
|
|
|
23.9 |
|
|
|
26.6 |
|
Onerous office lease settlements |
|
|
2.3 |
|
|
|
2.3 |
|
|
|
9.0 |
|
|
|
9.0 |
|
Settlement of restricted share units |
|
|
- |
|
|
|
0.1 |
|
|
|
- |
|
|
|
4.8 |
|
Deferred financing costs |
|
|
(0.5 |
) |
|
|
(0.6 |
) |
|
|
(2.3 |
) |
|
|
(2.3 |
) |
Transaction costs |
|
|
- |
|
|
|
- |
|
|
|
1.4 |
|
|
|
- |
|
Other expenses1 |
|
|
0.9 |
|
|
|
0.1 |
|
|
|
2.4 |
|
|
|
0.4 |
|
Funds flow from operations |
|
|
107.7 |
|
|
|
97.0 |
|
|
|
432.0 |
|
|
|
377.6 |
|
Capital expenditures |
|
|
(84.1 |
) |
|
|
(100.0 |
) |
|
|
(343.1 |
) |
|
|
(292.5 |
) |
Decommissioning expenditures |
|
|
(3.5 |
) |
|
|
(7.7 |
) |
|
|
(23.9 |
) |
|
|
(26.6 |
) |
Free cash flow |
|
$ |
20.1 |
|
|
$ |
(10.7 |
) |
|
$ |
65.0 |
|
|
$ |
58.5 |
|
(1)Excludes the non-cash portion of other expenses.
Netback to Sales Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
December 31 |
|
|
Year ended
December 31 |
|
(millions) |
|
2024 |
|
|
2023 |
|
|
2024 |
|
|
2023 |
|
Sales price |
|
$ |
213.8 |
|
|
$ |
173.6 |
|
|
$ |
818.8 |
|
|
$ |
722.8 |
|
Risk management gain (loss) |
|
|
6.0 |
|
|
|
6.7 |
|
|
|
21.6 |
|
|
|
17.7 |
|
Net sales price |
|
|
219.8 |
|
|
|
180.3 |
|
|
|
840.4 |
|
|
|
740.5 |
|
Royalties |
|
|
(29.0 |
) |
|
|
(25.0 |
) |
|
|
(106.5 |
) |
|
|
(97.8) |
|
Net operating costs |
|
|
(51.2 |
) |
|
|
(40.2 |
) |
|
|
(189.3 |
) |
|
|
(167.4) |
|
Transportation |
|
|
(16.8 |
) |
|
|
(10.8 |
) |
|
|
(57.9 |
) |
|
|
(41.0) |
|
Netback |
|
$ |
122.8 |
|
|
$ |
104.3 |
|
|
$ |
486.7 |
|
|
$ |
434.3 |
|
Net Operating Costs to Operating Costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
December 31 |
|
|
Year ended
December 31 |
|
(millions) |
|
2024 |
|
|
2023 |
|
|
2024 |
|
|
2023 |
|
Operating costs |
|
$ |
56.0 |
|
|
$ |
45.8 |
|
|
$ |
208.7 |
|
|
$ |
188.9 |
|
Less processing fees |
|
|
(2.9 |
) |
|
|
(3.6 |
) |
|
|
(12.4 |
) |
|
|
(14.3) |
|
Less road use recoveries |
|
|
(2.5 |
) |
|
|
(2.0 |
) |
|
|
(8.6 |
) |
|
|
(7.2) |
|
Realized power risk management loss |
|
|
0.6 |
|
|
|
- |
|
|
|
1.6 |
|
|
|
- |
|
Net operating costs |
|
$ |
51.2 |
|
|
$ |
40.2 |
|
|
$ |
189.3 |
|
|
$ |
167.4 |
|
Net Debt to Long-Term Debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at |
|
|
|
|
December 31 |
|
(millions) |
|
|
|
|
2024 |
|
2023 |
|
Long-term debt |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Syndicated credit facility |
|
|
|
|
|
|
|
|
|
$ |
225.0 |
|
|
$ |
107.5 |
|
Senior unsecured notes |
|
|
|
|
|
|
|
|
|
|
114.2 |
|
|
|
117.4 |
|
Unamortized discount of senior unsecured notes |
|
|
|
|
|
|
|
(1.1 |
) |
|
|
(1.6) |
|
Deferred financing costs |
|
|
|
|
|
|
|
|
|
|
(2.7 |
) |
|
|
(3.3) |
|
Total |
|
|
|
|
|
|
|
|
|
|
335.4 |
|
|
|
220.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Working capital deficiency |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash |
|
|
|
|
|
|
|
|
|
|
- |
|
|
|
(0.5) |
|
Accounts receivable |
|
|
|
|
|
|
|
|
|
|
(88.0 |
) |
|
|
(70.0) |
|
Prepaid expenses and other |
|
|
|
|
|
|
|
|
|
|
(12.0 |
) |
|
|
(12.8) |
|
Bank overdraft |
|
|
|
|
|
|
|
|
|
|
0.5 |
|
|
|
- |
|
Accounts payable and accrued liabilities |
|
|
|
|
|
|
|
|
|
|
175.8 |
|
|
|
193.5 |
|
Total |
|
|
|
|
|
|
|
|
|
|
76.3 |
|
|
|
110.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net debt |
|
|
|
|
|
|
|
|
|
$ |
411.7 |
|
|
$ |
330.2 |
|
ABBREVIATIONS
|
|
|
|
|
Oil |
Natural Gas |
|
bbl |
barrel or barrels |
AECO |
Alberta benchmark price for natural gas |
|
bbl/d |
barrels per day |
GJ |
gigajoule |
|
boe |
barrel of oil equivalent |
mcf |
thousand cubic feet |
|
boe/d |
barrels of oil equivalent per day |
mcf/d |
thousand cubic feet per day |
|
MSW |
Mixed Sweet Blend |
mmcf/d |
million cubic feet per day |
|
WTI |
West Texas Intermediate |
|
|
|
WCS |
Western Canadian Select |
|
|
|
|
FORWARD-LOOKING STATEMENTS
Certain statements contained in this document constitute forward-looking statements or information (collectively “forward-looking statements”) within the meaning of the "safe harbour" provisions of applicable securities legislation. Forward-looking statements are typically identified by words such as “anticipate”, “continue”, “estimate”, “expect”, “forecast”, “budget”, “may”, “will”, “project”, “could”, “plan”, “intend”, “should”, “believe”, “outlook”, “objective”, “aim”, “potential”, “target” and similar words suggesting future events or future performance. In addition, statements relating to “reserves” or “resources” are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated and can be profitably produced in the future. In particular, this document contains forward-looking
statements pertaining to, without limitation, the following: that we will file the annual audited consolidated financial statements and MD&A on our website, SEDAR+ and EDGAR in due course; our expected proceeds and closing date for the Transaction; our expected use of proceeds from the Transaction, our plan to evaluate the various opportunities to realize additional value from the InPlay Shares obtained from the Transaction; how we expect results to help define our development program and unlock future potential in certain areas; our expectations for drilling in the second half of 2025; the timing of our updated corporate presentation; the renewal of our NCIB; and our attendance at the Scotiabank Global Energy Conference.
With respect to forward-looking statements contained in this document, the Company has made assumptions regarding, among other things: that the tariffs that have been publicly announced by the U.S. and Canadian governments (but which are not yet in effect) do not come into effect, but that if such tariffs do come into effect, the potential impact of such tariffs, and that other than the tariffs that have been announced, neither the U.S. nor Canada: (i) increases the rate or scope of such tariffs or imposes new tariffs on the import of goods from one country to the other, including on oil and natural gas; and/or (ii) imposes any other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and natural gas; the ability of InPlay and Obsidian Energy to close the Transaction; Obsidian Energy’s view with respect to its financial condition and prospects, the stability of general economic and market conditions, currency exchange rates and interest rates; that the Company does not dispose of or acquire material producing properties or royalties or other interests therein other than as stated herein (provided that, except where otherwise stated, the forward-looking statements contained herein do not assume the completion of any transaction); that regional and/or global health related events will not have any adverse impact on energy demand and commodity prices in the future; global energy policies going forward, including the continued ability of members of OPEC+, Russia and other nations to agree on and adhere to production quotas from time to time; risks and uncertainties related to oil and gas interests and operations on Indigenous lands; our ability to qualify for (or continue to qualify for) new or existing government programs created as a result of new pandemics or otherwise, and obtain financial assistance therefrom, and the impact of those programs on our financial condition; our ability to comply with applicable terms and conditions under the Company’s debt agreements; the existence of alternative uses for Obsidian Energy's cash resources and compliance with applicable laws; our ability to execute our plans as described herein and in our other disclosure documents, including our three-year growth plan, and the impact that the successful execution of such plans will have on our Company and our stakeholders; future capital expenditure and decommissioning expenditure levels; future net operating costs and G&A costs; future crude oil, natural gas liquids and natural gas prices and differentials between light, medium and heavy oil prices and Canadian, WTI and world oil and natural gas prices; future hedging activities; future crude oil, natural gas liquids and natural gas production levels, including that we will not be required to shut-in production due to low commodity prices or the further deterioration of commodity prices; future exchange rates, tariffs and interest rates; future debt levels; our ability to execute our capital programs as planned without significant adverse impacts from various factors beyond our control, including extreme weather events, such as extreme cold, wild fires, flooding and drought, infrastructure access (including the potential for blockades or other activism) and delays in obtaining regulatory approvals and third party consents; our ability to obtain equipment in a timely manner to carry out development activities and the costs thereof; our ability to market our oil and natural gas successfully to current and new customers; our ability to obtain financing on acceptable terms, including our ability (if necessary) to continue to extend the revolving period and term out period of our Credit Facility; our ability to maintain the existing borrowing base under our Credit Facility if the Transaction is not completed and reduce it if the Transaction is completed; our ability (if necessary) to replace our syndicated bank facility and our ability (if necessary) to finance the repayment of our senior unsecured notes on maturity or pursuant to the terms of the underlying agreement; the accuracy of our estimated reserves volumes; our ability to add production and reserves through our development and exploration/appraisal activities; the expectation that InPlay will receive shareholder approval and all other necessary approvals for closing the Transaction; the expectation that the Company will receive the approval of its lenders under the Credit Facility for closing the Transaction; that all conditions of closing the Transaction will be met; that the Transaction will close on the timeline anticipated; and that the Company will achieve all the anticipated benefits of the Transaction.
Although the Company believes that the expectations reflected in the forward-looking statements contained in this document, and the assumptions on which such forward-looking statements are made, are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned not to place undue reliance on forward-looking statements included in this document, as there can be no assurance that the plans, intentions or expectations upon which the forward-looking statements are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties that contribute to the possibility that the forward-looking statements contained herein will not be correct, which may cause our actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. These risks and uncertainties include, among other things: the risk that (i) negotiations between the U.S. and Canadian governments are not successful and one or both of such governments implements announced tariffs, increases the rate or scope of announced tariffs, or imposes new tariffs on the import of goods from one country to the other, including on oil and natural gas, (ii) the U.S. and/or Canada imposes any other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and natural gas, and (iii) the tariffs imposed by the U.S. on other countries and responses thereto could have a material adverse effect on the Canadian, U.S. and global economies, and by extension the Canadian oil and natural gas industry and the Company; liabilities inherent in oil and natural gas operations; uncertainties associated with estimating oil and natural gas reserves; competition for, among other things, capital, acquisitions of royalty reserves, undeveloped lands and skilled personnel; incorrect assessments of the value of transactions, including the Transaction; Obsidian Energy’s future capital requirements; general economic and market conditions; demand for Obsidian Energy’s products; unforeseen legal or regulatory developments and other risk factors detailed from time to time in Obsidian Energy reports filed with the Canadian securities regulatory authorities and the United States Securities and Exchange Commission; the possibility that we change our budget in response to internal and external factors, including those described herein; the possibility that the Company will not be able to continue to successfully execute our business plans and strategies in part or in full, and the possibility that some or all of the benefits that the Company anticipates will accrue to our Company and our stakeholders as a result of the successful execution of such plans and strategies do not materialize; the possibility that the Company is unable to complete one or more of the potential transactions being pursued, on favorable terms or at all; the possibility that the Company ceases to qualify for, or does not qualify for, one or more existing or new government assistance programs implemented in connection regional and/or global health related events or otherwise, that the impact of such programs falls below our expectations, that the benefits under one or more of such programs is decreased, or that one or more of such programs is discontinued; the impact on energy demand and commodity prices of regional and/or global health related events, and the responses of governments and the public to any pandemic, including the risk that the amount of energy demand destruction and/or the length of the decreased demand exceeds our expectations; the risk that there is another significant decrease in the valuation of oil and natural gas companies and their securities and the decrease in confidence in the oil and natural gas industry generally whether caused by a pandemic, the worldwide transition towards less reliance on fossil fuels and/or other factors; the risk that the financial capacity of the Company's contractual counterparties is adversely affected and potentially their ability to perform their contractual obligations; the possibility that the revolving period and/or term out period of our Credit Facility and the maturity date of our senior unsecured notes is not further extended (if necessary), the borrowing base under our Credit Facility is reduced, and the Company is unable to renew or refinance our Credit Facility on acceptable terms or at all and/or finance the repayment of our senior unsecured notes when they mature on acceptable terms or at all and/or obtain new debt and/or equity financing to replace one or all of our credit facilities and senior unsecured notes; the possibility that we breach one or more of the financial covenants pursuant to our agreements with our lenders and the holders of our senior unsecured notes; the possibility that we are forced to shut-in production, whether due to commodity prices failing to rise or other factors; the risk that OPEC and other nations fail to agree on and/or adhere to production quotas from time to time that are sufficient to balance supply and demand fundamentals for crude oil; general economic and political conditions in Canada, the U.S. and globally, and in particular, the effect that those conditions have on commodity prices and our access to capital; the risk that wars and other armed conflicts adversely affect world economies and the demand for oil and natural gas, including the ongoing war between Russian and Ukraine and/or hostilities in the Middle East; industry conditions, including fluctuations in the price of crude oil, natural gas liquids and natural gas, price
differentials for crude oil and natural gas produced in Canada as compared to other markets, and transportation restrictions, including pipeline and railway capacity constraints; fluctuations in foreign exchange or interest rates; unanticipated operating events or environmental events that can reduce production or cause production to be shut-in or delayed (including extreme cold during winter months and hot during the spring and summer months, wild fires and flooding); the possibility that fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to hydrocarbons and technological advances in fuel economy and renewable energy generation systems could permanently reduce the demand for oil and natural gas and/or permanently impair the Company's ability to obtain financing on acceptable terms or at all, and the possibility that some or all of these risks are heightened as a result of the response of governments and consumers to public opinion and/or special interest groups; the risk that InPlay may not receive shareholder approval and all other necessary approvals for closing the Transaction; the risk that the Company's lenders under the Credit Facility may not consent to the Transaction; the risk that all conditions of closing the Transaction may not be met; the risk that the Transaction may not close when anticipated, or at all; the risk that the Company may not achieve all of the anticipated benefits of the Transaction; the risk that the Cash Proceeds from the Transaction may not be used as anticipated; the risk that the Company's 2024E net debt post-Transaction may be greater than anticipated; the risk that the Company's financial and operating results post-Transaction may not be consistent with its expectations; the risk that the Company may not realize the benefits anticipated from its InPlay Share position post-Transaction; the risk that the results of the Company's semi-annual borrowing base redetermination post-Transaction may not be consistent with its expectations; and the risk that the that the Company may not release its updated corporate presentation and guidance or other year end documents when anticipated. Additional information on these and other factors that could affect Obsidian Energy, or its operations or financial results, are included in the Company's Annual Information Form (see ’Risk Factors’ and ’Forward-Looking Statements’ therein) which may be accessed through the SEDAR+ website (www.sedarplus.ca), EDGAR website (www.sec.gov) or Obsidian Energy's website. Readers are cautioned that this list of risk factors should not be construed as exhaustive.
Unless otherwise specified, the forward-looking statements contained in this document speak only as of the date of this document. Except as expressly required by applicable securities laws, we do not undertake any obligation to publicly update or revise any forward-looking statements. The forward-looking statements contained in this document are expressly qualified by this cautionary statement.
Obsidian Energy shares are listed on both the Toronto Stock Exchange in Canada and the NYSE American in the United States under the symbol "OBE".
All figures are in Canadian dollars unless otherwise stated.
contact
OBSIDIAN ENERGY
Suite 200, 207 - 9th Avenue SW, Calgary, Alberta T2P 1K3
Phone: 403-777-2500
Toll Free: 1-866-693-2707
Website: www.obsidianenergy.com;
Investor Relations:
Toll Free: 1-888-770-2633
E-mail: investor.relations@obsidianenergy.com
Exhibit 99.2
Obsidian Energy Announces First Half 2025 Capital Program and Guidance
•Capital plan of 38 net operated wells weighted towards Peace River asset, following up on our 2024 development program
•Initiation of Clearwater waterflood program to support future Peace River growth
CALGARY, February 25, 2025 - OBSIDIAN ENERGY LTD. (TSX / NYSE American – OBE) (“Obsidian Energy”, the “Company”, “we”, “us” or “our”) is pleased to announce our first half 2025 capital plan and financial guidance that builds on the success of our 2024 program. With six drilling rigs currently in operation, the majority of our first half 2025 program is focused on Peace River with a significant component dedicated to exploration/appraisal drilling to further delineate our land position.
“Our recently announced agreement to dispose of our operated Pembina assets (the “Transaction”) to InPlay Oil Corp. (“InPlay”) has not changed our stated strategy for the Company: to drive heavy oil production growth at Peace River to approximately 25,000 boe/d in 2026 through delineation and development activities, while utilizing the stable cash flow from our light oil assets for reinvestment,” commented Stephen Loukas, Obsidian Energy’s President and CEO. “By focusing our Peace River exploration/appraisal activities largely in the first quarter, we can more effectively assess areas that are winter-only access to obtain key data that will help shape our future development plans. We have also planned an expanded Peace River development program for the first half of the year and will be following up on our strong 2024 drilling results at our Dawson field. Our Clearwater production grew substantially in 2024 from an average of 447 boe/d in January 2024 to average over 4,500 boe/d in December 2024 through organic development and a bolt-on acquisition. Additionally, we are initiating our first Clearwater waterflood pilot during the first half of 2025. We expect that the combination of these activities will result in higher future production levels, lower decline rates and increased recovery factors, furthering the continued development of our Peace River asset.”
Mr. Loukas continued, “The decision to enter into an agreement to sell our operated Pembina assets through the Transaction further focuses our Company and provides us with significantly enhanced liquidity and future optionality to add shareholder value. As such, we are evaluating our development plans for the second half of the year and expect to provide full-year guidance in June.”
First Half 2025 GUIDANCE
The Company plans between $185 and $195 million in capital expenditures (including approximately $24 million for exploration/appraisal drilling and $11 million for waterflood projects) plus an additional $11 to $12 million in decommissioning expenditures in the first half of 2025. First half production is expected to average approximately 33,800 boe/d (midpoint of guidance) – a three percent decrease from 35,006 boe/d in the first half of 2024, primarily due to the disposition Transaction1 that results in the net sale of approximately 10,000 boe/d of production. Peace River average production is expected to remain relatively flat over the first half of 2025 as many of our wells will not be onstream until the second quarter and several exploration wells will be shut in after evaluation due to seasonal access constraints. As a result, the majority of 2025 production gains will be realized during the second half of the year.
1 Obsidian Energy will include the results, including capital spending, of the disposed properties in the Transaction in our reported results up until the time of Transaction close, at which time we will adjust the purchase price to reflect those results. For the purposes of our guidance, we have assumed the Transaction closes March 31, 2025.
In the first half of 2025, net operating costs per boe are expected to be higher than 2024 levels due to increased trucking costs associated with our Peace River development and the benefit of reduced operating costs from the Transaction not occurring until the second quarter. Our 2025 guidance is based on lower commodity prices than in 2024, consisting of US$71.00/bbl WTI, US$5.00/bbl MSW differential, US$14/bbl WCS differentials and $2.00/GJ AECO natural gas. Our plan anticipates FFO of approximately $180 million, and a net debt to FFO ratio of approximately 0.7 times (based on annualized first half FFO and excluding any value for the InPlay share position from the Transaction). The Company’s net debt position will benefit from the enhanced liquidity provided by the Transaction. Our first half 2025 guidance is presented below.
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|
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H1 2025E Guidance |
Production1 |
boe/d |
|
|
33,300 – 34,300 |
% Oil and NGLs |
% |
|
|
72 |
Capital expenditures2 |
$ millions |
|
|
185 – 195 |
Decommissioning expenditures |
$ millions |
|
|
11 – 12 |
Net operating costs3 |
$/boe |
|
|
14.15 – 14.60 |
General & administrative |
$/boe |
|
|
1.75 – 1.85 |
|
|
Based on midpoint of above guidance |
|
WTI (Mar – June)4 |
US$/bbl |
|
|
71.00 |
MSW Differential (Mar – June)4 |
US$/bbl |
|
|
5.00 |
WCS Differential (Mar – June)4 |
US$/bbl |
|
|
14.00 |
AECO (Mar – June)4 |
$/GJ |
|
|
2.00 |
FFO3,5 |
$ millions |
|
|
180 |
FFO/share6 |
$/share |
|
|
2.44 |
FCF3,5 |
$ millions |
|
|
(22) |
FCF/share6 |
$/share |
|
|
(0.29) |
Net debt (prior to NCIB)7 |
$ millions |
|
|
240 |
Annualized net debt (prior to NCIB) to FFO7 |
times |
|
|
0.7 |
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|
|
|
|
Asset level information |
|
Heavy Oil |
Light Oil |
|
Average production |
boe/d |
12,900 |
20,900 |
|
Capital expenditures2 |
$ millions |
142 |
45 |
|
Net operating costs3 |
$/boe |
17.25 |
12.35 |
|
Netback3 |
$/boe |
34.00 |
31.50 |
|
Net operating income3 |
$ millions |
80 |
120 |
|
Asset level FCF |
$ millions |
(62) |
75 |
|
(1)Approximate mid-point of guidance range: 9,440 bbl/d light oil, 12,200 bbl/d heavy oil, 2,530 bbl/d NGLs and 57.8 mmcf/d natural gas. Average production volumes include a minimal amount of forecasted production associated with exploration/appraisal capital expenditures.
(2)Capital expenditures include approximately $34 million for Peace River exploration/appraisal and enhanced oil recovery waterflood activities with minimal impact on forecasted production volumes. Asset level capital does not include $3 million in corporate capital.
(3)We adhere to generally accepted accounting principles (“GAAP”); however, we also employ certain non-GAAP measures to analyze financial performance, financial position, and cash flow, including the terms FFO, FCF, net debt, netback, net operating costs and net operating income. Please refer to the ‘Non-GAAP and Other Financial Measures’ advisory section below for further detail.
(4)Pricing assumptions outlined are for the first half of 2025 and include risk management (hedging) adjustments as of February 24, 2025. WTI and AECO pricing as well as MSW and WCS differentials assumptions for the first half 2025E are forecasted for March to June 30, 2025. H1 2025E pricing assumptions, including actuals realized from January 1, 2025, to February 18, 2025, result in WTI of US$71.82/bbl, MSW differentials of US$4.93/bbl, WCS differentials of US$13.41/bbl, AECO of $2.00/GJ, and FX of 1.42x CAD/USD.
(5)FFO and FCF includes approximately $1 million of estimated charges for the first half of 2025 related to the deferred share units and performance share units cash compensation amounts, which are based on a share price of $7.66 per share.
(6)Per share calculations are based on an estimated 73.7 million weighted average shares outstanding for the six months ended June 30, 2025.
(7)Net debt figures estimated as at June 30, 2025. Figures do not include the impact of the $85 million in value of InPlay Oil Corp. common shares, which are to be received as part of the Transaction. If included, net debt would be reduced to $155 million with a 0.4x net debt (prior to NCIB) to FFO ratio. NCIB is the Company’s normal course issuer bid program.
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|
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Guidance Sensitivity Table |
Variable
|
Range |
Change in H1 2025E FFO ($ millions) |
WTI (US$/bbl) |
+/- $1.00/bbl |
2.9 |
MSW light oil differential (US$/bbl) |
+/- $1.00/bbl |
1.0 |
WCS heavy oil differential (US$/bbl) |
+/- $1.00/bbl |
0.8 |
Change in AECO ($/GJ) |
+/- $0.25/GJ |
1.0 |
H1 2025 capital and operating PROGRAM
Our first half capital program is well underway with five rigs active in Peace River drilling in the Clearwater and Bluesky formations, and a sixth rig drilling the four-well commitment in the Pembina area as part of the Transaction. The breakdown of operated wells expected to be rig released during the first half of 2025 is as follows:
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|
|
|
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H1 2025
Gross (Net) Wells |
DEVELOPMENT WELLS |
|
|
|
Heavy Oil Assets |
|
|
|
Peace River (Bluesky) |
|
|
13 (11.4) |
Peace River (Clearwater) |
|
|
14 (14.0) |
Light Oil Assets |
|
|
|
Pembina (Cardium)2 |
|
|
4 (4.0) |
|
|
|
31 (29.4) |
EXPLORATION/APPRAISAL WELLS |
|
|
|
Peace River (Bluesky) |
|
|
3 (3.0) |
Peace River (Clearwater) |
|
|
4 (4.0) |
|
|
|
7 (7.0) |
|
|
|
|
TOTAL OPERATED WELLS3,4 |
|
|
38 (36.4)1 |
|
(1)Three (3.0 net) wells rig released in 2024 were placed on production in the first quarter of 2025; they are excluded from the total. (2)Capital expenditures for the Pembina wells are for the account of InPlay and will be included in the statement of adjustments for the Transaction. (3)Excluding injection or disposal wells. (4)In addition, Obsidian Energy expects to participate in a total of five non-operated (2.2 net) wells in the first half of 2025. |
HEAVY OIL ASSETS (PEACE RIVER)
Over the first half of 2025, we will continue to delineate and appraise the broader Peace River land base of approximately 700 sections with a focus on expanding development drilling in successful fields from the additional 107 new follow-up Clearwater and Bluesky locations identified in 2024 (2P, booked locations). Exploration/appraisal drilling and new field delineation is a priority during the beginning of the year as winter conditions allow quick access to certain new fields, reducing capital costs. In 2025, we are using whipstock2 wells for exploration/appraisal purposes instead of oilsands exploration wells as they allow testing to delineate and de-risk an area, while at the same time providing new production as seasonal access allows. The Company is currently evaluating the technical results from recent whipstock drilling and well cores across Peace River to identify and assess new opportunities for future development.
Our first half Peace River capital program also includes enhanced oil recovery waterflood projects of approximately $11 million for a new Clearwater enhanced oil recovery and waterflood pilots with integrated
2 Whipstock drilling is a directional drilling technique that is used to change the direction of an existing wellbore, typically to sidetrack from an existing wellbore by drilling a new wellbore from the same wellhead. Obsidian Energy uses this technique to allow for drilling a vertical delineation well (with or without coring) prior to drilling horizontal production legs from the same wellbore.
producer and injection wells in Dawson and for additional injector conversions in the field. Peer waterfloods in the Clearwater formation have proven highly encouraging in increasing reservoir recovery and production, while mitigating decline rates at compelling returns.
Clearwater Formation
Obsidian Energy substantially grew our Clearwater production over the past year from 447 boe/d in January 2024 to average over 4,500 boe/d in December 2024, surpassing internal expectations due to high production rates from organic development as well as a strategic acquisition. During the first quarter of 2025, we plan to rig release a total of 18 (18.0 net) development and exploration/appraisal wells targeting the Clearwater formation.
•Exploration/Appraisal Program – Three of the four (4.0) net whipstock wells planned for the first half of the year have been drilled with core samples collected; production results are as follows:
oGift Lake: Our first Gift Lake exploration/appraisal well drilled at the 13-33 Pad in 2024 produced at a 30-day initial production (“IP”) rate of 92 boe/d (100 percent oil), successfully testing a second, lower Clearwater zone in the area and established the sand’s potential to expand this play. A follow up well at the 4-15 Pad designed to test the eastern extent of the field was drilled and placed on production in February. The well encountered Clearwater oil but is not commercially viable as oil rates have been below expectations with an average 22-day IP rate of 23 boe/d (100 percent oil) and a current steady rate of 33 boe/d (100 percent oil).
oNampa: We have currently rig released two of the three (3.0 net) 2025 exploration/appraisal wells designed to further delineate our acreage prior constructing year-round access for long-term development in the area.
▪Nampa 7-34 Pad: An offset well to the western Nampa 6-28 Pad drilled in 2024, the one (1.0 net) well produced at an average 19-day IP rate of 134 boe/d (100 percent oil) at a higher oil quality (API of approximately 15.9O). These early results are encouraging, further defining Nampa as a future development area for Clearwater after full season access is constructed.
▪Nampa 9-06 Pad: The two (2.0 net) exploration/appraisal wells at this pad are designed to test the multi-zone potential of the Clearwater formation, following our successful Nampa 6-28 Pad well drilled in the first quarter of 2024. We are currently drilling the second well, with both wells planned to be on production in mid-to late March.
•Development Program – Our first half 2025 development program focuses on Clearwater production growth in our Dawson field, which continues to produce at higher rates than initially forecasted. The Company intends to rig release 14 (14.0 net) multi-lateral production wells and two (2.0 net) injection wells at Dawson in the first half of 2025, drilling offset wells to follow the established productive trends through the field. We plan to keep two drilling rigs active in the area throughout the second quarter of 2025.
Bluesky Formation
We have expanded our Bluesky formation drilling in the first half of 2025 with 16 (14.4 net) wells planned for both development and exploration/appraisal purposes. The information gained from these wells is being used to better understand reservoir complexity and will help define our second half 2025 development program.
•Exploration/Appraisal Program – All three (3.0 net) whipstock wells planned for our first half of 2025 program have been rig released and are now temporarily on production: one (1.0 net) well at the Nampa 13-08 Pad; and one (1.0 net) well at each of the Harmon Valley South (“HVS”) 15-15 and
10-27 Pads, which will evaluate the Southern extent of the HVS field. The wells will undergo evaluation as seasonal access permits.
•Development Program – Our first half 2025 Bluesky development program consists of 13 (11.4 net) wells primarily focused on our HVS field to follow up on the strong production results of our new drilling and facility designs.
oHVS: A total of nine (8.3 net) wells are planned for the first half of 2025. Seven (7.0 net) offset wells at our HVS 13-08, HVS 14-07 and HVS 13-18 Pads, which follow up wells that achieved 30-day IP rates in the range of 450 to 500 boe/d /well (100 percent oil). The remaining two (1.3 net) wells are located off the HVS 16-09 Pad, which are farm-in wells with additional earning potential.
oWalrus: We are currently drilling the first of two (1.8 net) wells on the 7-21 Pad, one of which is a farm-in earning well for additional acreage in the area.
oSeal: We completed drilling two (1.3 net) farm-in wells at the 4-14 Pad to further test the potential of this field; both wells are expected to be placed onstream in early March.
•2024 Development Program Update: Results from the remainder of our 2024 program at the Walrus and Cadotte fields were lower than our internal expectations. Individual well clean up times of Bluesky wells vary between areas as a function of geographic changes in oil viscosity, reservoir properties like water saturation and surface handling capacity. Difficulties with start up activities, combined with higher than anticipated natural gas or water volumes, resulted in challenges with several of these wells.
oWalrus 15-01 Pad: The four (4.0) net wells at the pad continue to display very prolonged clean up times. Production is ramping up slowly as the wells are brought online and we monitor, evaluate and optimize the wells. Initial average production rates for the wells at the end of January 2025 varied between 15 and 151 bbl/d per well over various time periods. Currently, two wells have produced over 170 boe/d (100 percent oil) while two required early interventions; both ‘waffle-well’ designs display better performance compared to other standard linear offset wells. We expect that peak production will appear over the next two to three months as we continue to optimize this pad.
oCadotte: The remaining 2024 wells at Cadotte experienced higher water cuts and/or gas production than in other areas, resulting in multiple well start-up issues and the shut in of wells to bring the pads online. We continue to manage these challenges to increase future production.
▪13-15 Pad: We have initially experienced more water volumes than expected on this three-well pad, which has impacted the pace of the wells cleaning up. The third well on this pad was shut in during February due to high water volumes combined with water handling constraints. With one of the earlier wells experiencing high water cuts, Obsidian Energy is evaluating alternative water disposal options in the area that would allow for reduced trucking from the pad and production to resume at all three wells.
▪ 9-36 Pad: This pad encountered an unexpected, localized gas zone, resulting in large gas volumes that continues to impact our ability to place all three wells onstream. Obsidian Energy is evaluating the extent of the gas zone and if the tie-in of the wells and revised surface facilities needed for continued production are economic to proceed.
Light Oil ASSETS
The Company has one rig in operation for our first half 2025 light oil program to drill four wells for InPlay (at their expense) as part of the disposition Transaction. We anticipate returning to drilling our light oil assets in the second half of the year, including at the Willesden Green Unit#2 where we are increasing our working interest as part of the Transaction.
•Willesden Green (Belly River): Our 2024 initial delineation well targeting the Belly River formation at the 15-06 Pad returned to production in late January. Production response from the well is encouraging as the well continues to clean up. The well produced at a 30-day IP rate of 100 boe/d (77 percent oil) and displays continuous improvement – averaging 221 boe/d (76 percent oil) over the last 25 days as
water volumes drop. Opening a new play for the Company, success with this well provides follow-up locations and adds highly economic, lower decline production to our light oil portfolio.
•Pembina (Cardium): We rig released three of the four (4.0 net) Cardium development wells on the
8-01 and 2-25 Pads, undertaken as part of the Transaction. Two of the four wells are online, and we anticipate the remaining two wells will be on production in April.
•Pembina (Cardium, Non-Operated): Following up on the success in 2024, Obsidian Energy is participating in five (2.2 net) wells in the first half of the year at the Pembina Cardium Unit #11
(~45 percent working interest). Four of the wells have been rig released and all wells are expected on production early in the second quarter of 2025.
ADDITIONAL READER ADVISORIES
OIL AND GAS INFORMATION ADVISORY
Barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of crude 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. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is misleading as an indication of value.
ABBREVIATIONS
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Oil |
Natural Gas |
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API |
American Petroleum Institute |
AECO |
Alberta benchmark price for natural gas |
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bbl |
barrel or barrels |
GJ |
gigajoule |
|
bbl/d |
barrels per day |
mcf |
thousand cubic feet |
|
boe |
barrel of oil equivalent |
mcf/d |
thousand cubic feet per day |
|
boe/d |
barrels of oil equivalent per day |
mmcf/d |
million cubic feet per day |
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MSW |
Mixed Sweet Blend |
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WTI |
West Texas Intermediate |
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WCS |
Western Canadian Select |
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NON-GAAP AND OTHER FINANCIAL MEASURES
Throughout this news release and in other materials disclosed by the Company, we employ certain measures to analyze financial performance, financial position, and cash flow. These non-GAAP and other financial measures do not have any standardized meaning prescribed by International Financial Reporting Standards (“IFRS”) and therefore may not be comparable to similar measures provided by other issuers. The non-GAAP and other financial measures should not be considered to be more meaningful than GAAP measures which are determined in accordance with IFRS, such as net income (loss) and cash flow from operating activities as indicators of our performance. The Company's audited consolidated financial statements and management’s discussion and analysis (“MD&A”) as at and for the year ended December 31, 2024, are available on the Company's website at www.obsidianenergy.com and under our SEDAR+ profile at www.sedarplus.ca and EDGAR profile at www.sec.gov. The disclosure under the section ’Non-GAAP and Other Financial Measures’ in the MD&A is incorporated by reference into this news release.
Non-GAAP Financial Measures
The following measures are non-GAAP financial measures: FFO; FCF; net debt; netback; net operating costs; and net operating income. These non-GAAP financial measures are not standardized financial
measures under IFRS and might not be comparable to similar financial measures disclosed by other issuers. See the disclosure under the section ’Non-GAAP and Other Financial Measures’ in our MD&A for the year ended December 31, 2024, for an explanation of the composition of these measures, how these measures provide useful information to an investor, and the additional purposes, if any, for which management uses these measures.
Non-GAAP Ratios
The following measures are non-GAAP ratios: FFO (basic per share ($/share)), which use FFO as a component; FCF (basic per share ($/share)), which use FCF as a component; net operating costs ($/boe), which uses net operating costs as a component; and net debt to funds flow from operations, which uses net debt and funds flow from operations as a component. These non-GAAP ratios are not standardized financial measures under IFRS and might not be comparable to similar financial measures disclosed by other issuers. See the disclosure under the section ’Non-GAAP and Other Financial Measures’ in our MD&A for the year ended December 31, 2024, for an explanation of the composition of these non-GAAP ratios, how these non-GAAP ratios provide useful information to an investor, and the additional purposes, if any, for which management uses these non-GAAP ratios.
Supplementary Financial Measures
The following measure is a supplementary financial measure: general and administrative costs ($/boe). See the disclosure under the section ’Non-GAAP and Other Financial Measures’ in our MD&A for the year ended December 31, 2024, for an explanation of the composition of this measure.
FUTURE-ORIENTED FINANCIAL INFORMATION
This release contains future-oriented financial information (“FOFI”) and financial outlook information relating to the Company's prospective results of operations, operating costs, expenditures, production, FFO, FCF, net operating costs, and net debt, which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth below under ’Forward-Looking Statements’. The Company's actual results, performance or achievement could differ materially from those expressed in, or implied by, such FOFI, or if any of them do so, what benefits the Company will derive therefrom. The Company has included this FOFI to provide readers with a more complete perspective on the Company's business as of the date hereof and such information may not be appropriate for other purposes.
Without limitation of the foregoing, this news release contains information regarding our growth plans, guidance for our first half 2025 capital expenditures; first half 2025 production levels, FFO, FFO per share, FCF, FCF per share, net operating costs, net debt (prior to NCIB) and net debt (prior to NCIB) to FFO ratio, which are based on various factors and assumptions that are subject to change including regarding production levels, commodity prices, operating and other costs and capital expenditure levels, and in the case of the periods other than the first half of 2025, such estimates are provided for illustration purposes only and are based on budgets and plans that have not been finalized and are subject to a variety of contingencies including prior years' results. To the extent that such estimates constitute FOFI or a financial outlook, they were approved by management of the Company on February 24, 2025, and are included to provide readers with an understanding of the Company's anticipated plans and financial results based on the capital expenditures and other assumptions described and readers are cautioned that the information may not be appropriate for other purposes.
FORWARD-LOOKING STATEMENTS
Certain statements contained in this document constitute forward-looking statements or information (collectively “forward-looking statements”) within the meaning of the "safe harbour" provisions of applicable securities legislation. Forward-looking statements are typically identified by words such as “anticipate”, “continue”, “estimate”, “expect”, “forecast”, “budget”, “may”, “will”, “project”, “could”, “plan”, “intend”, “should”, “believe”, “outlook”, “objective”, “aim”, “potential”, “target” and similar words suggesting future events or future performance. In addition, statements relating to “reserves” or “resources” are
deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated and can be profitably produced in the future. In particular, this document contains forward-looking statements pertaining to, without limitation, the following: our long-term growth strategy; how we plan to shape our future development plans; our development plan for both our light and heavy assets in the first half of 2025 and exploration/appraisal wells; our expectations for the Company after the completion of the Transaction; our first half 2025 guidance for production, production mix, capital and decommissioning expenditures, net operating costs, G&A costs, FFO, FFO/share, FCF, FCF/share, net debt (prior to NCIB), and net debt (prior to NCIB) to FFO; our guidance sensitivities; our flexibility to our program as commodity prices change; how we plan to fund our first half 2025 programs; our expected optionality for our second half 2025 capital program; our non-operated well expectations; expected timing for drilling, rig releases, on-production and onstream dates; our expectations in connection with our Bluesky and Clearwater acreage; our expectations in connection with the Transaction; how we plan to delineate, de-risk and appraise our land base and assess new opportunities for future development; our expectations for our waterflood program; our expected peak production and optimization for certain pads; and how we plan to manage certain production challenges.
With respect to forward-looking statements contained in this document, the Company has made assumptions regarding, among other things: that the tariffs that have been publicly announced by the U.S. and Canadian governments (but which are not yet in effect) do not come into effect, but that if such tariffs do come into effect, the potential impact of such tariffs, and that other than the tariffs that have been announced, neither the U.S. nor Canada: (i) increases the rate or scope of such tariffs or imposes new tariffs on the import of goods from one country to the other, including on oil and natural gas; and/or (ii) imposes any other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and natural gas; the ability of InPlay and Obsidian Energy to close the Transaction; Obsidian Energy’s view with respect to its financial condition and prospects, the stability of general economic and market conditions, currency exchange rates and interest rates, and our ability to comply with applicable terms and conditions under the Company’s debt agreements, the availability of cash or other financing sources to fund for repurchases of common shares under the NCIB and our ability to comply with applicable terms and conditions under the Company’s debt agreements; that the Company does not dispose of or acquire material producing properties or royalties or other interests therein other than as stated herein (provided that, except where otherwise stated, the forward-looking statements contained herein do not assume the completion of any transaction); that regional and/or global health related events will not have any adverse impact on energy demand and commodity prices in the future; global energy policies going forward, including the continued ability of members of OPEC+, Russia and other nations to agree on and adhere to production quotas from time to time; risks and uncertainties related to oil and gas interests and operations on Indigenous lands; our ability to qualify for (or continue to qualify for) new or existing government programs created as a result of new pandemics or otherwise, and obtain financial assistance therefrom, and the impact of those programs on our financial condition; our ability to comply with applicable terms and conditions under the Company’s debt agreements; the existence of alternative uses for Obsidian Energy's cash resources and compliance with applicable laws; our ability to execute our plans as described herein and in our other disclosure documents, including our growth plan, and the impact that the successful execution of such plans will have on our Company and our stakeholders; future capital expenditure and decommissioning expenditure levels; future net operating costs and G&A costs; future crude oil, natural gas liquids and natural gas prices and differentials between light, medium and heavy oil prices and Canadian, WTI and world oil and natural gas prices; future hedging activities; future crude oil, natural gas liquids and natural gas production levels, including that we will not be required to shut-in production due to low commodity prices or the further deterioration of commodity prices; future exchange rates, tariffs and interest rates; future debt levels; our ability to execute our capital programs as planned without significant adverse impacts from various factors beyond our control, including extreme weather events, such as extreme cold, wild fires, flooding and drought, infrastructure access (including the potential for blockades or other activism) and delays in obtaining regulatory approvals and third party consents; our ability to obtain equipment in a timely manner to carry out development activities and the costs thereof; our ability to market our oil and natural gas successfully to current and new customers; our ability to obtain financing on acceptable terms, including our ability (if necessary) to continue to extend the revolving period and term out period of our Credit Facility; our ability to maintain the existing borrowing base
under our Credit Facility if the Transaction is not completed and reduce it if the Transaction is completed; our ability (if necessary) to replace our syndicated bank facility and our ability (if necessary) to finance the repayment of our senior unsecured notes on maturity or pursuant to the terms of the underlying agreement; the accuracy of our estimated reserves volumes; our ability to add production and reserves through our development and exploration/appraisal activities; the expectation that InPlay will receive shareholder approval and all other necessary approvals for closing the Transaction; the expectation that the Company will receive the approval of its lenders under the Credit Facility for closing the Transaction; that all conditions of closing the Transaction will be met; that the Transaction will close on the timeline anticipated; and that the Company will achieve all the anticipated benefits of the Transaction.
Although the Company believes that the expectations reflected in the forward-looking statements contained in this document, and the assumptions on which such forward-looking statements are made, are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned not to place undue reliance on forward-looking statements included in this document, as there can be no assurance that the plans, intentions or expectations upon which the forward-looking statements are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties that contribute to the possibility that the forward-looking statements contained herein will not be correct, which may cause our actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. These risks and uncertainties include, among other things: the risk that (i) negotiations between the U.S. and Canadian governments are not successful and one or both of such governments implements announced tariffs, increases the rate or scope of announced tariffs, or imposes new tariffs on the import of goods from one country to the other, including on oil and natural gas, (ii) the U.S. and/or Canada imposes any other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and natural gas, and (iii) the tariffs imposed by the U.S. on other countries and responses thereto could have a material adverse effect on the Canadian, U.S. and global economies, and by extension the Canadian oil and natural gas industry and the Company; liabilities inherent in oil and natural gas operations; uncertainties associated with estimating oil and natural gas reserves; competition for, among other things, capital, acquisitions of royalty reserves, undeveloped lands and skilled personnel; incorrect assessments of the value of transactions, including the Transaction; Obsidian Energy’s future capital requirements; general economic and market conditions; demand for Obsidian Energy’s products; unforeseen legal or regulatory developments and other risk factors detailed from time to time in Obsidian Energy reports filed with the Canadian securities regulatory authorities and the United States Securities and Exchange Commission; the possibility that we change our budget in response to internal and external factors, including those described herein; the possibility that the Company will not be able to continue to successfully execute our business plans and strategies in part or in full, and the possibility that some or all of the benefits that the Company anticipates will accrue to our Company and our stakeholders as a result of the successful execution of such plans and strategies do not materialize; the possibility that the Company is unable to complete one or more of the potential transactions being pursued, on favorable terms or at all; the possibility that the Company ceases to qualify for, or does not qualify for, one or more existing or new government assistance programs implemented in connection regional and/or global health related events or otherwise, that the impact of such programs falls below our expectations, that the benefits under one or more of such programs is decreased, or that one or more of such programs is discontinued; the impact on energy demand and commodity prices of regional and/or global health related events, and the responses of governments and the public to any pandemic, including the risk that the amount of energy demand destruction and/or the length of the decreased demand exceeds our expectations; the risk that there is another significant decrease in the valuation of oil and natural gas companies and their securities and the decrease in confidence in the oil and natural gas industry generally whether caused by a pandemic, the worldwide transition towards less reliance on fossil fuels and/or other factors; the risk that the financial capacity of the Company's contractual counterparties is adversely affected and potentially their ability to perform their contractual obligations; the possibility that the revolving period and/or term out period of our Credit Facility and the maturity date of our senior unsecured notes is not further extended (if necessary), that the borrowing base under our Credit Facility is reduced, that the Company is unable to renew or refinance our Credit Facility on acceptable terms or at all and/or finance the repayment of our senior unsecured notes when they mature on acceptable terms or at all and/or obtain new debt and/or equity financing to replace one or all of our credit facilities and senior unsecured notes;
the possibility that we breach one or more of the financial covenants pursuant to our agreements with our lenders and the holders of our senior unsecured notes; the possibility that we are forced to shut-in production, whether due to commodity prices failing to rise or other factors; the risk that OPEC and other nations fail to agree on and/or adhere to production quotas from time to time that are sufficient to balance supply and demand fundamentals for crude oil; general economic and political conditions in Canada, the U.S. and globally, and in particular, the effect that those conditions have on commodity prices and our access to capital; the risk that wars and other armed conflicts adversely affect world economies and the demand for oil and natural gas, including the ongoing war between Russian and Ukraine and/or hostilities in the Middle East; industry conditions, including fluctuations in the price of crude oil, natural gas liquids and natural gas, price differentials for crude oil and natural gas produced in Canada as compared to other markets, and transportation restrictions, including pipeline and railway capacity constraints; fluctuations in foreign exchange or interest rates; unanticipated operating events or environmental events that can reduce production or cause production to be shut-in or delayed (including extreme cold during winter months and hot during the spring and summer months, wild fires and flooding); the possibility that fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to hydrocarbons and technological advances in fuel economy and renewable energy generation systems could permanently reduce the demand for oil and natural gas and/or permanently impair the Company's ability to obtain financing on acceptable terms or at all, and the possibility that some or all of these risks are heightened as a result of the response of governments and consumers to public opinion and/or special interest groups; the risk that InPlay may not receive shareholder approval and all other necessary approvals for closing the Transaction; the risk that the Company's lenders under the Credit Facility may not consent to the Transaction; the risk that all conditions of closing the Transaction may not be met; the risk that the Transaction may not close when anticipated, or at all; the risk that the Company may not achieve all of the anticipated benefits of the Transaction; the risk that the cash proceeds from the Transaction may not be used as anticipated; the risk that the Company's 2024E net debt post-Transaction may be greater than anticipated; the risk that the Company's financial and operating results post-Transaction may not be consistent with its expectations; the risk that the Company may not realize the benefits anticipated from its InPlay Share position post-Transaction; the risk that the results of the Company's semi-annual borrowing base redetermination post-Transaction may not be consistent with its expectations; and the risk that the Company may not release its updated corporate presentation and guidance or other year end documents when anticipated. Additional information on these and other factors that could affect Obsidian Energy, or its operations or financial results, are included in the Company's Annual Information Form (see ’Risk Factors’ and ’Forward-Looking Statements’ therein) which may be accessed through the SEDAR+ website (www.sedarplus.ca), EDGAR website (www.sec.gov) or Obsidian Energy's website. Readers are cautioned that this list of risk factors should not be construed as exhaustive.
Unless otherwise specified, the forward-looking statements contained in this document speak only as of the date of this document. Except as expressly required by applicable securities laws, we do not undertake any obligation to publicly update or revise any forward-looking statements. The forward-looking statements contained in this document are expressly qualified by this cautionary statement.
Obsidian Energy shares are listed on both the Toronto Stock Exchange in Canada and the NYSE American in the United States under the symbol "OBE".
All figures are in Canadian dollars unless otherwise stated.
contact
OBSIDIAN ENERGY
Suite 200, 207 - 9th Avenue SW, Calgary, Alberta T2P 1K3
Phone: 403-777-2500
Toll Free: 1-866-693-2707
Website: www.obsidianenergy.com;
Investor Relations:
Toll Free: 1-888-770-2633
E-mail: investor.relations@obsidianenergy.com
Obsidian Energy (AMEX:OBE)
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