• Average production of 27,971 boe/d in the fourth quarter, generated $56.6 million of funds flow from operations

• Successful 2025 capital program including waterflood initiatives resulted in reserve replacement ratios over 100%

• Active prepaid equity forward program in Q4/25 and into 2026 with a total of 4.3 million shares purchased

Calgary, Alberta--(Newsfile Corp. - February 19, 2026) - OBSIDIAN ENERGY LTD. (TSX:OBE) (NYSE: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 2025.

		Three months ended December 31						Year ended December 31
		2025			2024			2025			2024
FINANCIAL
(millions, except per share amounts)
Cash flow from operating activities	$	42.6		$	115.0		$	239.8		$	361.9
Basic per share ($/share)¹		0.63			1.55			3.45			4.76
Diluted per share ($/share)¹		0.62			1.49			3.34			4.57
Funds flow from operations²		56.6			107.7			272.1			432.0
Basic per share ($/share)³		0.84			1.45			3.92			5.69
Diluted per share ($/share)³		0.82			1.39			3.79			5.46
Net income		(12.3	)		(284.8	)		35.2			(202.6	)
Basic per share ($/share)		(0.18	)		(3.83	)		0.51			(2.67	)
Diluted per share ($/share)		(0.18	)		(3.83	)		0.49			(2.67	)
Capital expenditures		65.0			84.1			298.9			343.1
Property acquisitions (dispositions), net		2.6			(1.5	)		(208.0	)		83.4
Decommissioning expenditures		10.3			3.5			28.8			23.9
Long-term debt		179.9			335.4			179.9			335.4
Net debt²	$	268.2		$	411.7		$	268.2		$	411.7

OPERATIONS
Daily Production
Light oil (bbl/d)		5,443			13,271			7,340			13,463
Heavy oil (bbl/d)		12,782			11,621			12,080			9,016
NGL (bbl/d)		2,037			3,176			2,308			3,077
Natural gas (mmcf/d)		46			72			53			72
Total production⁴ (boe/d)		27,971			40,119			30,624			37,474

Average sales price (before hedging)¹
Light oil ($/bbl)	$	75.30		$	96.95		$	90.96		$	99.95
Heavy oil ($/bbl)		59.10			67.70			64.41			70.46
NGL ($/bbl)		35.33			44.27			42.49			48.05
Natural gas ($/mcf)	$	2.38		$	1.53		$	1.90		$	1.52
Netback ($/boe)
Sales price	$	48.17		$	57.94		$	53.73		$	59.70
Risk management gain		2.75			1.62			0.65			1.58
Net sales price		50.92			59.56			54.38			61.28
Royalties		(4.81	)		(7.85	)		(6.55	)		(7.76	)
Transportation		(5.28	)		(4.55	)		(4.78	)		(4.22	)
Net operating costs³		(15.19	)		(13.91	)		(14.92	)		(13.85	)
Netback³($/boe)	$	25.64		$	33.25		$	28.13		$	35.45

(1) Supplementary financial measure. See 'Non-GAAP and Other Financial Measures'.
(2) Non-GAAP financial measure. See 'Non-GAAP and Other Financial Measures'.
(3) Non-GAAP ratio. See 'Non-GAAP and Other Financial Measures'.
(4) Please refer to the 'Oil and Gas Information Advisory' section below for information regarding the term "boe".

PRESIDENTS MESSAGE

"Obsidian Energy had a very dynamic year in 2025; from closing the sale of our operated Pembina assets in April for ~$325 million, to moderating capital spending as WTI oil prices fell due to announced tariffs in the United States, while returning capital to shareholders via the execution of our share buyback program and driving strong reserve replacement metrics via our development program" commented Stephen Loukas, Obsidian Energy's President and CEO. "As we closed out 2025, we maintained our balanced capital program between our Willesden Green and Peace River areas. In Willesden Green, we drilled a successful Belly River program and completed an infrastructure project in Open Creek which is being utilized on our 2026 wells and will allow for future production growth. In Peace River, our capital program was focused in the Clearwater formation and we advanced our waterflood initiatives in both the Dawson and Nampa areas. Late in the fourth quarter, our base operations in Peace River were impacted by extreme cold weather and significant snowfall, which affected trucking routes and resulted in an increase in oil inventories. This temporary interruption reduced fourth quarter production by approximately 500 boe/d. We were back to normal operations by mid-January and expect to reduce the oil inventory build over the next few months."

Mr. Loukas continued, "During the fourth quarter we continued executing our prepaid equity forward program to help mitigate the impact of our share-based compensation plans. In 2025, we purchased ~3.3 million shares under this program and have remained active in 2026 with an incremental ~1.0 million purchased. We are also in the process of renewing our normal course issuer bid ("NCIB"), which should be in place in early March."

2025 FOURTH QUARTER AND FULL YEAR CORPORATE HIGHLIGHTS

Funds Flow from Operations - The Company generated FFO of $272.1 million ($3.92 per share basic) compared to $432 million ($5.69 per share basic) in the prior year. Fourth quarter 2025 FFO totaled $56.6 million ($0.84 per basic share) compared to $107.7 million ($1.45 per basic share) in the fourth quarter of 2024. Lower oil prices as well as lower production levels post our disposition of the Pembina assets in April 2025 were the main drivers of the variance from 2024.

Capital Program - Our 2025 capital program focused on further development and delineation of our Peace River asset, progressing on waterflood initiatives with two pilots in Peace River and active drilling in Open Creek, including drilling wells in the emerging Belly River formation with strong initial results. Our capital program was ahead of schedule in late 2025 which allowed us to add incremental injector wells and bring forward the start of our 2026 capital program. Capital expenditures totaled $298.9 million (2024: $343.1 million), while decommissioning expenditures totaled $28.8 million (2024: $23.9 million). Fourth quarter capital expenditures were $65.0 million (2024: $84.1 million) and decommissioning expenditures were $10.3 million (2024: $3.5 million).

Pembina Asset Disposition - In April 2025, the Company closed the disposition to InPlay Oil Corp. ("InPlay") of our operated Pembina (Cardium) assets ("Pembina Disposition"). Total consideration (including final InPlay share sale proceeds) was approximately $325 million with the proceeds from the disposition applied against our syndicated credit facility. The transaction included all the Company's operated assets in Pembina which had first quarter 2025 average production of approximately 11,000 boe/d.
- Our decommissioning liability was reduced by over 50% with a total of $390 million removed from our portfolio on an undiscounted, uninflated basis, including $189 million associated with inactive properties.
- The Company also acquired InPlay's 34.6 percent interest in the Willesden Green Cardium Unit #2 property as part of the transaction.

Net Debt - Net debt levels decreased to $268.2 million at December 31, 2025, compared to $411.7 million at December 31, 2024, mainly due to the Company applying the proceeds of the Pembina Disposition to our outstanding debt.
- On December 31, 2025, the Company had $9 million outstanding on our $235 million syndicated credit facility.
- In December 2025, the Company completed a refinancing and issued five-year senior unsecured notes for an aggregate principal amount of $175.0 million with an interest rate of 8.125 percent (the “Notes”). These Notes mature on December 3, 2030. The Company used the net proceeds from the Notes to redeem all of our previous outstanding 11.95% senior unsecured notes due July 27, 2027, and to pay down outstanding amounts on our syndicated credit facility.

Active Share Buyback Program - A total of approximately 7.6 million shares were repurchased and cancelled under the Company's NCIB for $54.9 million (at an average price of $7.20 per share) in 2025. There have been no shares repurchased since August 2025 when we reached the maximum purchase allotment approved under the current NCIB.
- Since the inception of our NCIB program in 2023, we have repurchased and cancelled approximately 17.2 million shares at an average price of $8.37 per share for $143.9 million.
- We are currently in the process of renewing our NCIB and expect to be in a position to potentially commence repurchases in March 2026 upon renewal.

Prepaid Equity Forward Program - We continued to enter prepaid equity forward contracts on our shares
- A total of 3,340,000 shares were purchased in 2025 for $28.7 million or $8.62 per share.
- Subsequent to December 31, 2025, an incremental 950,000 shares were purchased for a total of $9.1 million or $9.57 per share.

Net Operating Costs - Net operating costs were higher in 2025 at $14.92 per boe (2024: $13.85 per boe) and $15.19 per boe for the fourth quarter of 2025 (2024: $13.91 per boe) as a result of higher trucking costs and processing fees in Peace River due to our expanded operations in the area. Late in the fourth quarter of 2025, Peace River operations were negatively impacted by extreme cold weather and significant snowfall which resulted in higher repair & maintenance activity while also temporarily reducing production. We anticipate operating costs per boe to decrease in 2026 as additional water disposal capabilities are expected to reduce trucking expenses in Peace River.

G&A Costs - General and administrative ("G&A") costs were $1.84 per boe in 2025 compared to $1.50 per boe in 2024, and $1.98 per boe in the fourth quarter of 2025 compared to $1.39 per boe for the same quarter in 2024. G&A costs increased on a per boe basis given our lower production levels as a result of the Pembina Disposition.

Net Income - The Company recorded net income of $35.2 million ($0.51 per share basic) in 2025 compared to a net loss of $202.6 million ($(2.67) per share basic) in 2024. In 2025, net income was the result of the Company's positive operating results combined with lower depletion and depreciation expense resulting from the Pembina Disposition. This was partially offset by lower production revenues due to the lower oil pricing and lower production amounts following the closing of the Pembina Disposition.

2025 FOURTH QUARTER AND FULL YEAR CAPITAL PROGRAM & HIGHLIGHTS

Our 2025 capital program consisted of further development and delineation in both Peace River and Willesden Green. In the first half of the year, we focused on primary development as well as exploration in Peace River, specifically in Harmon Valley South ("HVS") and Dawson. Our program in the second half of the year was balanced between heavy and light oil assets with continued development in Peace River, particularly in the Clearwater, in addition to advancing waterflood initiatives with one pilot in Dawson (Clearwater) and another in HVS (Bluesky). In Willesden Green, we were active in Open Creek, including drilling initial wells in the emerging Belly River formation with strong results. Capital program highlights for 2025 are as follows:

Operated Wells Rig Released and On Production - We rig released a total of 63 (61.4 net) wells and brought 58 (56.4 net) wells on production by the end of 2025, contributing to reserve additions.

Total Gross (Net) Wells	Operated Wells Rig Released		Operated Wells On Production
Heavy Oil Assets
Peace River (Bluesky)	14 (12.4	)	16 (14.4	)
Peace River (Clearwater)	26 (26.0	)	25 (25.0	)
Light Oil Assets
Willesden Green (Cardium)	4 (4.0	)	-
Willesden Green (Belly River)	3 (3.0	)	3 (3.0	)
Pembina (Cardium)	4 (4.0	)	4 (4.0	)
Mannville	1 (1.0	)	1 (1.0	)
	52 (50.4	)	49 (47.4	)
EXPLORATION/APPRAISAL WELLS
Injector Wells	4 (4.0	)	2 (2.0	)
Peace River (Clearwater)	4 (4.0	)	4 (4.0	)
Peace River (Bluesky)	3 (3.0	)	3 (3.0	)
	11 (11.0	)	9 (9.0	)

TOTAL OPERATED WELLS	63 (61.4	)	58 (56.4	)

(1) During the year we brought on 58 (56.4 net) operated wells including testing of two wells before they were converted to injectors. We also participated in an additional 12 (5.4 net) non-operated wells drilled into PCU#11.

Solid Reserve Performance with Strong Reserve Replacement Ratios - We achieved strong results with volume increases across all categories, replacing production, adding new locations, and improved efficiency of our capital program (excluding dispositions).

Reserve replacement with 118 percent on a proved developed producing ("PDP") reserves basis, 185 percent on a proved ("1P") reserves basis and 235 percent on a proved + probable ("2P") reserves basis, based on 2025 production (adjusted for dispositions) and driven by the impact of drilling infill wells and field extensions in both Peace River and Willesden Green.
Reserves before-tax net present value discounted at 10 percent ("NPV10") to $1.0 billion, $1.4 billion and $2.1 billion for PDP, 1P and 2P, respectively.
Future Development Capital ("FDC") is moderated in both the 1P and 2P reserve categories to reflect the current commodity price environment, the Pembina disposition and anticipated capital spending levels. FDC generates a five-year program of approximately $243 million per year on a 2P reserve basis.
Our total undeveloped 2P reserve locations (excluding the impact of the Pembina disposition) increased by 39 net locations to 357 total net locations booked, with 22 net new locations in Willesden Green and 20 net new location in Peace River offset by a reduction of 3 net locations in Viking.

130 net locations in Willesden Green/PCU #11;
- (Cardium 113 locations, Belly River 14 locations, Mannville 3 locations)
103 net locations in the Peace River (Clearwater);
77 net locations in the Peace River (Bluesky); and
47 net locations in the Viking.

Reserve life index ("RLI") continues to be stable with approximately 6.0, 10.1 and 13.3 years on a PDP, 1P, and 2P reserves basis.

Active Decommissioning Program - We successfully abandoned a combined total of 58 net wells and 34 net kilometres of pipeline in 2025 as part of activities from our decommissioning spend of $28.8 million. We will be able to use approximately $4 million of this amount to reduce our 2026 Alberta Energy Regulator ("AER") spending obligation.

SECOND HALF 2025 GUIDANCE

A comparison of our second half guidance metrics to actual results is outlined below. During the fourth quarter of 2025, our operations in Peace River were impacted by extreme cold weather and significant snow accumulation. This led to issues transporting our oil out of the area and increased our tank inventory, ultimately impacting our production volumes by approximately 500 boe/d for the quarter. Additionally, our net operating costs were higher than expected due to unplanned repair and maintenance activity as a result of freeze-ups and the substantial snowfall. We were back to normal operations by mid-January and anticipate the inventory build will be reduced to normalized levels over the next few months. Additionally, capital expenditures exceeded our guidance due to our election to advance drilling certain 2026 waterflood injector wells into 2025 as our overall Peace River program finished ahead of schedule, as well as incremental land purchases. Our FFO was below the midpoint of our guidance due to the lower production and higher operating costs previously discussed, as well as lower oil prices.

		H2 2025E Guidance	H2 2025 Actuals
Production¹	boe/d	27,800 - 28,300	27,644
% Oil and NGLs	%	72	72
Capital expenditures	$ millions	120 - 125	130.3
Decommissioning expenditures	$ millions	14 - 15	18.2
Net operating costs³	$/boe	14.35 - 14.60	15.10
General & administrative	$/boe	1.95 - 2.05	1.97

Based on midpoint of above guidance
FFO³	$ millions	114	106.3
FFO/share³	$/share	1.70	1.58
FCF³	$ millions	(23)	(42.2)
FCF/share³	$/share	(0.34)	(0.63)
Net debt³	$ millions	235	268.2
Net debt to annualized FFO³	times	1.0	1.3
Pricing assumptions²
WTI	US$/bbl	60.00	58.67
Foreign Exchange Rate	CAD/USD	1.40	1.39
MSW Differential	US$/bbl	4.00	3.59
WCS Differential	US$/bbl	11.50	12.00
AECO	$/GJ	2.75	2.71

Asset level information, based on midpoint of above guidance		H2 2025E Guidance	H2 2025 Actuals
Heavy Oil
Average production	boe/d	13,900	13,622
Capital expenditures	$ millions	64	69
Net operating costs³	$/boe	18.10	19.77
Netback³	$/boe	27.80	26.31
Net operating income³	$ millions	70	66
Asset level FCF	$ millions	6	(3)

Light Oil
Average production	boe/d	14,150	14,022
Capital expenditures	$ millions	58	60
Net operating costs³	$/boe	10.35	10.15
Netback³	$/boe	23.65	22.36
Net operating income³	$ millions	60	58
Asset level FCF	$ millions	2	(2)

(1) Refer to 'Supplemental Production Disclosure' below for details of production by product types.
(2) Second half guidance pricing assumptions included risk management (hedging) adjustments as of October 29, 2025. WTI, Foreign Exchange and AECO price assumptions for second half 2025 guidance and actuals are for November to December 2025 only given our H2 2025E guidance was updated on October 30, 2025. MSW and WCS differential assumptions for the second half 2025 guidance and actuals are for December 2025 only.
(3) See "Non-GAAP and Other Financial Measures" section below for further details.

HEDGING UPDATE

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

Oil Contracts

Type	Volume (bbls/d)	Remaining Term		Price ($/bbl)
Oil
WTI Swap	6,127	January 2026	CAD$	84.12
WTI Swap	13,298	February 2026	US$	62.47
WTI Swap	12,800	March 2026	US$	64.13
WTI Swap	8,000	April 2026	US$	64.29
WTI Swap	2,000	May 2026	US$	63.70

AECO Natural Gas Contracts

Type	Volume (mcf/d)	Remaining Term		Price ($/mcf)
Natural Gas
AECO Swap	26,540	January 2026 - March 2026	$	3.30
AECO Swap	35,377	April 2026 - October 2026		2.68
AECO Swap	1,896	November 2026 - March 2027	$	3.73

Equity Forward Contracts

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	450,000	January 2029		8.76
Equity Forward Contract	555,000	February 2029	$	10.10

FX Forward Contracts

Type	Notional Amount ($millions)	Remaining Term		Price (C$)
FX forward contract	2.5	January 2026	$	1.3840
FX forward contract	19.0	February 2026		1.3719
FX forward contract	16.0	March 2026		1.3686
FX forward contract	13.5	April 2026	$	1.3650

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.

ABOUT OBSIDIAN ENERGY

Obsidian Energy is an intermediate-sized oil and gas producer with a well-balanced portfolio of high-quality assets, primarily in the Peace River, Willesden Green and Viking areas in Alberta. The Company's business is to explore for, develop and hold interests in oil and natural gas properties and related production infrastructure in the Western Canada Sedimentary Basin.

Obsidian Energy is headquartered in Calgary and listed on the Toronto Stock Exchange and NYSE American (TSX:OBE) (NYSE:OBE). To learn more, visit Obsidian Energy's website.

ADDITIONAL READER ADVISORIES

SUPPLEMENTAL PRODUCTION DISCOSURE

Outlined below is expected average production by product based on the midpoint of our H2 2025 guidance estimates and actual average production for H2 2025.

Based on midpoint of guidance		H2 2025E Guidance	H2 2025 Actuals
Heavy Oil	bbl/d	13,000	12,684
Light Oil	bbl/d	5,300	5,211
NGLs	bbl/d	1,950	1,996
Natural gas	mmcf/d	46.8	46.5
Total Production	boe/d	28,050	27,644

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 "FDC", which does not have standardized meaning or standard methods of calculation and therefore such measure 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.

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.

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 consolidated financial statements and MD&A for the year ended December 31, 2025, 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, 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.

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 in our MD&A for year ended December 31, 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 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, 2025, 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, except per share amounts)		2025			2024			2025			2024
Cash flow from operating activities	$	42.6		$	115.0		$	239.8		$	361.9
Change in non-cash working capital		(17.5	)		(13.5	)		(30.6	)		35.7
Decommissioning expenditures		10.3			3.5			28.8			23.9
Equity forward contracts		21.3			-			28.7			-
Onerous office lease settlements		-			2.3			0.7			9.0
Deferred financing costs		(0.3	)		(0.5	)		(1.7	)		(2.3	)
Restructuring charges		0.1			-			1.0			-
Transaction costs		0.1			-			5.4			1.4
Other expenses		-			0.9			-			2.4
FFO		56.6			107.7			272.1			432.0
Capital expenditures		(65.0	)		(84.1	)		(298.9	)		(343.1	)
Decommissioning expenditures		(10.3	)		(3.5	)		(28.8	)		(23.9	)
Free Cash Flow	$	(18.7	)	$	20.1		$	(55.6	)	$	65.0

Netback to Sales Price

		Three months ended December 31						Year ended December 31
(millions)		2025			2024			2025			2024
Sales price	$	123.9		$	213.8		$	600.5		$	818.8
Risk management gain		7.1			6.0			7.3			21.6
Net sales price		131.0			219.8			607.8			840.4
Royalties		(12.4	)		(29.0	)		(73.2	)		(106.5	)
Transportation		(13.6	)		(16.8	)		(53.4	)		(57.9	)
Net operating costs		(39.0	)		(51.2	)		(166.7	)		(189.3	)
Netback	$	66.0		$	122.8		$	314.5		$	486.7

Net Operating Costs to Operating Costs

		Three months ended December 31						Year ended December 31
(millions)		2025			2024			2025			2024
Operating costs	$	43.5		$	56.0		$	183.5		$	208.7
Less processing fees		(3.0	)		(2.9	)		(10.1	)		(12.4	)
Less road use recoveries		(1.5	)		(2.5	)		(6.7	)		(8.6	)
Add realized power risk management loss		-			0.6			-			1.6
Net operating costs	$	39.0		$	51.2		$	166.7		$	189.3

Net Debt to Long-Term Debt

		As at December 31
(millions)		2025			2024
Long-term debt
Syndicated credit facility	$	9.0		$	225.0
Senior unsecured notes (8.125%, maturing December 3, 2030)		175.0			-
Senior unsecured notes (11.95%, maturing July 27, 2027)		-			114.2
Unamortized discount of senior unsecured notes		-			(1.1	)
Deferred financing costs		(4.1	)		(2.7	)
Total		179.9			335.4

Working capital deficiency
Accounts receivable		(56.1	)		(88.0	)
Prepaid expenses and other		(11.0	)		(12.0	)
Bank overdraft		0.4			0.5
Accounts payable and accrued liabilities		155.0			175.8
Total		88.3			76.3

Net debt	$	268.2		$	411.7

ABBREVIATIONS

Oil		Natural Gas
bbl	barrel or barrels	mcf	thousand cubic feet
bbl/d	barrels per day	mcf/d	thousand cubic feet per day
boe	barrel of oil equivalent	mmcf	million cubic feet
boe/d	barrels of oil equivalent per day	mmcf/d	million cubic feet per day
MSW	Mixed Sweet Blend	mmbtu	Million British thermal unit
WTI	West Texas Intermediate	AECO	Alberta benchmark price for natural gas
WCS	Western Canadian Select	NGL	natural gas liquids
		GJ	gigajoule

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 expectations for our crude inventories over the next few months; that we plan to renew the NCIB in March 2026; our expectations for operating costs per boe in 2026; our undeveloped 2P reserves locations, FDC and RLI; that we will be able to use certain decommissioning spend incurred in 2025 in 2026 to reduce our AER spending obligation; our corporate guidance for production, capital and decommissioning expenditures, net operating costs, G&A costs, FFO, FFO/share, FCF, FCF/share, net debt and net debt to annualized FFO; our updated asset level guidance for production, capital, net operating costs, netback, net operating income, and asset level FCF; our hedges; the timing of our updated corporate presentation; and that we will file our consolidated financial statements and MD&A on our website, SEDAR+ and EDGAR in due course.

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 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 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.

The future acquisition by the Company of the Company's common shares pursuant to its share buyback program (including through its NCIB), if any, and the level thereof is uncertain. Any decision to acquire common shares of the Company pursuant to the share buyback program will be subject to the discretion of the board of directors of the Company and may depend on a variety of factors, including, without limitation, the Company's business performance, financial condition, financial requirements, growth plans, expected capital requirements and other conditions existing at such future time including, without limitation, contractual restrictions and satisfaction of the solvency tests imposed on the Company under applicable corporate law. There can be no assurance of the number of common shares of the Company that the Company will acquire pursuant to its share buyback program, if any, in the future.

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 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 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 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 Notes or to fund other activities; the possibility that we are unable to complete one or more repurchase offers pursuant to our Notes when otherwise required to do so; 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 and Venezuela; 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.

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

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Obsidian Energy Announces Fourth Quarter and Full Year 2025 Results