Exhibit 99.1

Obsidian Energy Announces 2026 Guidance and Provides an Operational Update

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Capital expenditures guidance of $210 million (midpoint) resulting in 38 net operated wells drilled at both Peace River and Willesden Green including $22 million in waterflood spending

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Production guidance of 28,900 boe/d (midpoint) for 2026, approximately 55% weighted to our light oil assets and 45% weighted to our heavy oil assets

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Funds flow from operations of $225 million ($3.35 per basic share) based on WTI of US$58.00/bbl in H1 2026 and US$62.00/bbl in H2 2026

CALGARY, January 22, 2026 - OBSIDIAN ENERGY LTD. (TSX / NYSE American – OBE) (“Obsidian Energy”, the “Company”, “we”, “us” or “our”) is pleased to announce our 2026 capital plan and guidance as well as provide an operational update on our successful 2025 development program.

“Building off strong results in recent years, our 2026 capital program continues to advance the delineation and development of both our light and heavy oil assets and furthers our waterflood initiatives in Peace River”, commented Stephen Loukas, Obsidian Energy’s President and CEO. “In Willesden Green, the light oil program is centred on further development in Open Creek, predominately in the Belly River formation, as we benefit from new infrastructure in the area that we constructed in late 2025. In Peace River, our capital program is a combination of primary development in both the Bluesky and Clearwater formations while also progressing waterflood projects in both the Dawson and Nampa areas. While we are early in the execution of our enhanced oil recovery strategy in Peace River, we are encouraged by the results to-date, and we plan to expand efforts in the area in 2026 and beyond.”

Mr. Loukas continued, “We employed a disciplined approach to our 2026 plans given the current volatility in commodity prices, resulting in a small free cash flow positive budget for the year (prior to any potential share repurchases) while marginally growing production. We believe that the near-term pricing environment is likely to remain volatile, however, we anticipate a more constructive commodity price environment in the second half of the year and into 2027. As a result, the program is designed to maximize our 2026 production exit rate, with the waterflood spend driving a reduction to our projected 2027 decline rate. Additionally, we have significant optionality with drill ready projects, both in Peace River (Bluesky and Clearwater), and Willesden Green (Belly River and Cardium), allowing us to scale up quickly should higher commodity prices present themselves. Alternatively, if we see further commodity price weakness, we are also prepared to scale back our program with respect to primary drilling. Furthermore, we anticipate renewing our normal course issuer bid (“NCIB”) in March 2026. The pace at which we purchase shares may vary depending on a number of factors including the macro environment, as we maintain our financial flexibility and balance sheet strength”.

2026 GUIDANCE

Our 2026 capital budget is set at $190 to $230 million resulting in average production guidance of 27,900 to 29,900 boe/d (73% liquids). Capital expenditures are a combination of development in both our light and heavy oil assets, with $128 million allocated to Willesden Green/Pembina Cardium Unit #11 (“PCU #11”) and $80 million to heavy oil assets in Peace River. Included in the capital budget for Peace River is approximately $22 million focused on progressing waterflood initiatives in the area with a focus on the Dawson and Nampa areas. At the mid-point of production guidance, we estimate our sustaining capital (excluding waterflood capital) is approximately $175 million, which we expect to trend lower as future production decline rates benefit from current waterflood initiatives.

Our guidance levels assume WTI US$58.00/bbl for the first half of 2026 and WTI US$62.00/bbl for the second half of 2026 with full year AECO natural gas at $2.75/GJ. At these pricing levels we are forecasting to generate approximately $225 million of funds flow from operations (“FFO”) while generating ~$7 million of positive free cash flow (“FCF”). We anticipate net operating costs to average $14.00 - $15.00 boe/d as we focus on multiple cost reduction initiatives across our portfolio.

Further asset level details for our 2026 budget are as follows:

Heavy Oil (Peace River)

Our 2026 development activities will be split approximately evenly between our Bluesky and Clearwater formations. In addition to this primary development program, we plan to drill 8 (8.0 net) Clearwater waterflood injection wells, building on our waterflood projects in 2025. The program is strategically designed to prioritize Clearwater injector projects in the first half of the year, while focusing on Bluesky development drilling in the second half of the year when we anticipate that commodity prices will improve. Capital expenditures of $80 million (mid-point of guidance) have been allocated to our heavy oil assets for the year, with the following details:

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A total of 26 (26.0 net) wells planned, including multi-lateral, open hole producers as well as integrated horizontal waterflood injectors.

Development in the Bluesky formation will continue in our Harmon Valley South (“HVS”) and Cadotte fields with 9 (9.0 net) wells planned, including one appraisal well.

In the Clearwater formation 9 (9.0 net) producers anticipated.

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Continued emphasis on waterflood initiatives with $22 million of capital allocated including drilling 8 (8.0 net) injection wells in the first half of the year, across our Nampa, West Dawson and Dawson fields. By the end of 2026, the Company will have approximately 35% of our Clearwater production waterflood supported.

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We retain optionality to expand waterflood activities in the second half of the year to drill a further 9 (9.0 net) injectors at Dawson for $14 million, subject to continued positive results and commodity prices.

Light Oil (Willesden Green/ PCU#11)

In 2026, we will continue to focus development in both our Open Creek and Crimson areas, predominately delineating the Belly River formation where the 2025 drilling program experienced strong success. With the recent completion of a pipeline infrastructure project in Open Creek, we will benefit from lower equip and tie in costs as we expand our production base in the area. A total of $128 million of capital expenditures (mid-point of guidance) have been allocated to light oil assets for the year, which includes completion activities for wells drilled in late 2025 in Open Creek and PCU#11, and the following highlights:

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Development will consist of a one rig program, which includes a total of 12 (12.0 net) wells, consisting of 10 wells in Open Creek, with 6 (6.0 net) wells focused on the Belly River and 4 (4.0 net) wells on the Cardium. In Crimson 2 (2.0 net) wells will be drilled also focused on the Belly River.

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In Open Creek, the 11-28 Pad will be our first pad with both Cardium and Belly River development wells from the same surface location. This technique should result in significant efficiencies within our development program in future years.

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Our non-operated program at PCU #11 (~45 percent working interest) will remain active with a 10-well (4.5 net) program planned in 2026.

Details of our 2026 guidance and pricing assumptions are outlined below.


		2026 Guidance
Production1	boe/d	27,900 – 29,900
% Oil and NGLs	%	73%
Capital expenditures2	$ millions	190 – 230
Decommissioning expenditures3	$ millions	7 – 11
Net operating costs4	$/boe	14.00 – 15.00
General & administrative	$/boe	2.00 – 2.10

Based on midpoint of above guidance
FFO4	$ millions	225
FFO/share2,4	$/share	3.35
FCF4	$ millions	7
FCF/share2,4	$/share	0.10
Net debt (prior to NCIB)4,5	$ millions	272
Annualized net debt (prior to NCIB) to FFO4,5	Times	1.2

Pricing assumptions2
WTI (January – June 2026)	US$/bbl	58.00
WTI (July – December 2026)	US$/bbl	62.00
Foreign Exchange Rate	CAD/USD	1.38
MSW Differential	US$/bbl	3.50
WCS Differential	US$/bbl	13.50
AECO	$/GJ	2.75


Asset level information, based on midpoint of above guidance		2026 Guidance
Heavy Oil
Average production	boe/d	12,700
% Oil and NGLs	%	93%
Capital expenditures2	$ millions	80
Net operating costs4	$/boe	20.20
Netback4	$/boe	19.00
Net operating income4	$ millions	88
Asset level FCF	$ millions	8

Light Oil
Average production	boe/d	16,200
% Oil and NGLs	%	58%
Capital expenditures2	$ millions	128
Net operating costs4	$/boe	10.05
Netback4	$/boe	30.45
Net operating income4	$ millions	180
Asset level FCF	$ millions	52

(1)

Refer to ‘Supplemental Production Disclosure’ below for details of production by product types.

(2)

Refer to “Budget Assumptions Information” below for further details.

(3)

The Company’s estimated AER spending closure obligation for 2026 remains subject to change in accordance with the terms and conditions of the agreement of purchase and sale governing the Company’s disposition of its Pembina assets to InPlay Oil Corp in 2025.

(4)

See “Non-GAAP and Other Financial Measures” section below for further details.

(5)

Net debt figures exclude the impact of potential purchases under our NCIB, which we plan to renew in March 2026. Net debt includes prepaid equity forwards of approximately $21 million in Q4 2025 and approximately $3 million in 2026 to-date.

Estimated sensitivities to selected key assumptions on FFO for 2026 are as follows:


Guidance Sensitivity Table
Variable	Range	Change in 2026 FFO ($ millions)
WTI (US$/bbl)	+/- $1.00/bbl	9.4
Foreign Exchange Rate (CAD/USD)	+/- $0.01	3.4
MSW light oil differential (US$/bbl)	+/- $1.00/bbl	3.6
WCS heavy oil differential (US$/bbl)	+/- $1.00/bbl	6.1
AECO ($/GJ)	+/- $0.25/GJ	1.6

2026 capital and operating PROGRAM

The breakdown of operated wells expected to be rig released in 2026 is as follows:


	Well Type			Total
	Development	Appraisal	Injector	Gross (Net)
DEVELOPMENT WELLS
Heavy Oil Assets
H1 Peace River (Bluesky)	1 (1.0)	1 (1.0)	-	2 (2.0)
H1 Peace River (Clearwater)1	8 (8.0)	-	7 (7.0)	15 (15.0)

H2 Peace River (Bluesky)	7 (7.0)	-	-	7 (7.0)
H2 Peace River (Clearwater)	-	1 (1.0)	1 (1.0)	2 (2.0)

Light Oil Assets
H1 Willesden Green (Belly River)	5 (5.0)	-	-	5 (5.0)
H1 Willesden Green (Cardium)	-	-	-	-

H2 Willesden Green (Belly River)	3 (3.0)	-	-	3 (3.0)
H2 Willesden Green (Cardium)	4 (4.0)	-	-	4 (4.0)

TOTAL OPERATED WELLS2	28 (28.0)	2 (2.0)	8 (8.0)	38 (38.0)

(1)

Including the last well of our 2025 program rig released on January 2, 2026

(2)

In addition, Obsidian Energy expects to participate in a total of 10 non-operated (4.5 net) wells in 2026.

OPERATIONAL UPDATE

During the fourth quarter of 2025, the Company completed our second half capital program at both Peace River and Willesden Green. In Peace River, we focused on primary development in the Clearwater at Dawson while also continuing our waterflood initiatives as we completed two Bluesky projects. In Willesden Green, our successful Belly River development continued with two (2.0 net) new wells brought on production during the quarter. Key highlights are as follows:

Heavy Oil (Peace River)

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Active Development Program – Rig-released 7 (7.0 net) wells in the area in the fourth quarter, including 5 (5.0 net) Clearwater wells, and 2 (2.0 net) Clearwater injection wells in the Dawson field. This included wells that were accelerated into the year as faster than anticipated drilling times had us ahead of schedule.

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Strong Initial Rates – Brought on production 6 (6.0 net) Clearwater wells during the quarter, with initial production (“IP”) rates as follows:

05-27 pad Dawson (Clearwater) – 3 (3.0 net) wells with an average IP30 of 230 boe/d (100% oil) per well

07-18 pad Peavine (Clearwater) – 3 (3.0 net) wells with an average IP30 of 209 boe/d (100% oil) per well

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Road Infrastructure Project – We continued construction on a major road infrastructure project in the Nampa field into the fourth quarter. This road infrastructure allowed for the re-activation of approximately 200 bbl/d of previously shut-in Clearwater production in December 2025. The drilling rig utilized this new infrastructure to move into the Nampa field late 2025 to spud our Nampa integrated -waterflood pilot and delineation wells.

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Waterflood – Our waterflood injection program continues to progress in Peace River. Two Bluesky waterflood projects were completed, with injection commencing during the fourth quarter. In addition to the water injection, the Company will also see lower net operating costs in the area as we will now reduce third party disposal fees. In the Clearwater at the Dawson 04-24 pad, we are seeing encouraging early production response from the two injector wells drilled that began injecting in the third quarter of 2025. Subsequently two additional injector wells were drilled and completed from this 04-24 pad and were placed on injection in mid-January.

Light Oil (Willesden Green)

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Open Creek Infrastructure Project - During the fourth quarter, we completed our Open Creek infrastructure project. This was recently commissioned in early January and now connects this underdeveloped field into our regional infrastructure system. With this infrastructure now operational, the additional capacity will allow the Company to significantly increase the pace of activity in both the Belly River and Cardium plays.

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Expanded Open Creek Development – Our recent Belly River wells at the 06-33 Pad have seen steady production increases as the wells were optimized, however, cleanup was prolonged partially due to back pressure on the wells. The pad recorded an IP30 average per well of 199 boe/d (86% liquids) but has subsequently increased to 418 boe/d (80% liquids) over the last 10 days as the commissioning of the new infrastructure was completed. Our Open Creek development continued at the end of 2025 with four (4.0 net) Cardium wells rig-released and now completed on the 11-15 pad, which will be brought on production into the new gathering system in February.

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Mannville Well Update – We drilled one (1.0 net) Mannville well which came on production in the quarter, with an IP30 of 468 boe/d (28% liquids). We are closely monitoring the progress on this well given it has performed below our internal expectations.

Light Oil (PCU #11)

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Completion of 2025 program – During the quarter the 12-well development program was finished with the rig-release of six (2.7 net) Cardium wells. Frac operations began in January with on production dates planned for February.

HEDGING UPDATE

Currently, we have the following contracts outstanding on a weighted average basis:


Type	Volume (bbls/d)		Remaining Term		Price ($/bbl)
Oil
WTI Swap		6,127	January 2026	$		84.12

Revenue		Notional Amount ($ millions)	Remaining Term			FX Rate (USD/CAD)
FX forward contract		2.5	January 2026	$		1.3840
FX forward contract		3.0	February 2026			1.3842
FX forward contract		3.0	March 2026	$		1.3842


Type	Volume (mcf/d)		Remaining Term		Price ($/mcf)
Natural Gas
AECO Swap		26,540	January 2026 - March 2026	$		3.30
AECO Swap		34,360	April 2026 - October 2026			2.71
AECO Swap		1,896	November 2026 - March 2027	$	3.73


Type	Share Volume		Remaining Term		Price (C$)
Equity
Equity Forward Contract		720,000	September 2028	$		8.89
Equity Forward Contract		1,300,000	October 2028			8.72
Equity Forward Contract		550,000	November 2028			8.43
Equity Forward Contract		715,000	December 2028			8.31
Equity Forward Contract		390,000	January 2029	$		8.70

ADDITIONAL READER ADVISORIES

SUPPLEMENTAL PRODUCTION DISCOSURE

Outlined below is expected average production by product based on the midpoint of our 2026 guidance estimates.


Based on midpoint of guidance		2026 Guidance
Heavy Oil	bbl/d	11,800
Light Oil	bbl/d	7,300
NGLs	bbl/d	2,000
Natural gas	mmcf/d	46.8
Total Production	boe/d	28,900

BUDGET ASSUMPTIONS INFORMATION

Capital Expenditures

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Asset level capital does not include $1 million in corporate capital.

Commodity Pricing

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2026 pricing assumptions include risk management (hedging) adjustments as of January 14, 2026. WTI assumption for the first half of 2026 (January – June) is US$58.00/bbl and second half 2026 (July – December) is US$62.00/bbl.

Per Share Calculations

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Per share calculations are based on an estimated 67.2 million weighted average shares outstanding for the year ended December 31, 2026.

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.

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.

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

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 interim consolidated financial statements and MD&A as at and for three and nine months ended September 30, 2025, 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; net debt; net operating costs; netback; and 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 three- and nine-month period ended September 30, 2025, 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 ($/share) and diluted per share ($/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 in our MD&A for three and nine months ended September 30, 2025, 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: G&A costs ($/boe). See the disclosure under the section ’Non-GAAP and Other Financial Measures’ in our MD&A for the three and nine months ended September 30, 2025, for an explanation of the composition of these measures.

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 guidance for our 2026 capital expenditures, production levels, FFO, FFO per share, FCF, FCF per share, net operating costs, net debt (prior to NCIB) and annualized 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. To the extent that such estimates constitute FOFI or a financial outlook, they were approved by management of the Company on January 21, 2026, 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 development plans for 2026 and beyond; our expectations for free cash flow for 2026 (prior to any potential share repurchases); our expectations for near-term pricing and the second half of the year and into 2027; our optionality in the program should higher or lower prices occur in 2026, including waterflood initiatives; how we plan to design our 2026 program to maximize our production exit rate and the impacts of our waterflood spend on our projected 2027 decline rate; our expectations for the NCIB in 2026; the expected breakdown of expenditures for our light and heavy programs (including Bluesky and Clearwater formations), our sustaining capital amounts including our expectation for it to trend lower with lower production decline rates; our expected drilling program, including waterflood initiatives; our expectations for waterflood support by the end of 2026 in the Clearwater; our expectations for equip and tie in costs in the Open Creek area; our expectations for our non-operated program in 2026; our estimated AER spending closure obligation for 2026 which remains subject to change in accordance with the terms and conditions of the agreement of purchase and sale governing the Company’s disposition of its Pembina assets to InPlay Oil Corp in 2025; our 2026 guidance for production (including mixture and type), capital and decommissioning expenditures, net operating costs, general & administrative costs, FFO and FFO/share, FCF and FCF/share, Net debt (prior to NCIB) and Annualized net debt to FFO (prior to NCIB); our expected sensitivities to changes in WTI, foreign exchange, MSW, AECO and WCS; our guidance for asset level average production, capital expenditures, net operating costs, netbacks, net operation income and the asset level FCF; our expected rig releases in 2026; the expectations for development pace in the Open Creek area with the completion of the infrastructure project; expected on-production dates for certain wells; and our hedges.

With respect to forward-looking statements contained in this document, the Company has made assumptions regarding, among other things: the duration and impact of tariffs that are currently in effect on goods exported from or imported into Canada, and that other than the tariffs that are currently in effect, neither the U.S. nor Canada (i) increases the rate or scope of such tariffs, reenacts tariffs that are currently suspended, 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; that the Company does not dispose of or acquire material producing properties or royalties or other interests therein (except as disclosed herein); 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 and willingness of members of OPEC and other nations to agree on and adhere to production quotas from time to time; our ability to qualify for (or continue to qualify for) new or existing government programs, and obtain financial assistance therefrom, and the impact of those programs on our financial condition; our ability to execute our plans as described herein and in our other disclosure documents, and the impact that the successful execution of such plans will have on our Company and our stakeholders, including our ability to return capital to shareholders and/or further reduce debt levels; future capital expenditure and decommissioning expenditure levels; expectations and assumptions concerning applicable laws and regulations, including with respect to environmental, safety and tax matters; future operating costs and G&A costs and the impact of inflation thereon; future 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 oil, natural gas liquids and natural gas production levels; future exchange rates, interest rates and inflation 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 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; the ability of the Company's contractual counterparties to perform their contractual obligations; 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 extend the revolving period and term out period of our credit facility, our ability to maintain the existing borrowing base under our credit facility, 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 reserve volumes; and our ability to add production and reserves through our development and exploitation activities.

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) the tariffs that are currently in effect on goods exported from or imported into Canada continue in effect for an extended period of time, the tariffs that have been threatened are implemented, that tariffs that are currently suspended are reactivated, the rate or scope of tariffs are increased, or new tariffs are imposed, 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 or threatened to be imposed by the U.S. on other countries and retaliatory tariffs imposed or threatened to be imposed by other countries on the U.S., will trigger a broader global trade war which 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, including by decreasing demand for (and the price of) oil and natural gas, disrupting supply chains, increasing costs, causing volatility in global financial markets, and limiting access to financing; the possibility that we change our budgets (including our capital expenditure budgets) 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 (such as our inability to return capital to shareholders and/or reduce debt levels to the extent anticipated 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, 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 thereto, 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 in confidence in the oil and natural gas industry generally, whether caused by regional and/or global health related events, 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 extended (if necessary), that the borrowing base under our credit facility is reduced, that the Company is unable to renew or refinance our credit facilities 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 our credit facilities and/or senior unsecured notes or to fund other activities; the possibility that we are forced to shut-in production, whether due to commodity prices decreasing, extreme weather events such as wild fires, inability to access our properties due to blockades or other activism, 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 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; industry conditions, including fluctuations in the price of oil, natural gas liquids and natural gas, price differentials for 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, including the impact of the Canadian/U.S. dollar exchange rate on our revenues and expenses; fluctuations in interest rates, including the effects of interest rates on our borrowing costs and on economic activity, and including the risk that elevated interest rates cause or contribute to the onset of a recession; the risk that our costs increase due to inflation, supply chain disruptions, scarcity of labour and/or other factors, adversely affecting our profitability; 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, wild fires, flooding and droughts (which could limit our access to the water we require for our

operations)); 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; the possibility that fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to hydrocarbons, government mandates requiring the sale of electric vehicles and/or electrification of the power grid, 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 and/or insurance 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, financial institutions and consumers to a regional and/or global health related event and/or the influence of public opinion and/or special interest groups.

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 LTD. 6-K