Obsidian Energy Ltd.: Obsidian Energy Announces First Quarter 2025 Results

• Closed $320 million divestiture of Pembina assets on April 7, 2025, with cash proceeds used to reduce debt level

• Completed first quarter program with 26 (24.4 net) operated wells rig released and 19 (17.9 net) operated wells brought on production

• Responded to the market environment by reducing our first half capital program to $165 - $170 million from $185 - $195 million

• Commenced drilling waterflood injector pilot at the Dawson 4-24 Pad

Calgary, Alberta--(Newsfile Corp. - May 7, 2025) - OBSIDIAN ENERGY LTD. (TSX: OBE) (NYSE American: OBE) ("Obsidian Energy", the "Company", "we", "us" or "our") is pleased to report our operating and financial results for the first quarter of 2025.

					Three months ended March 31
					2025		2024
FINANCIAL1 (millions, except per share amounts)
Cash flow from operating activities						96.7	58.7
Basic per share ($/share)2						1.32	0.76
Diluted per share ($/share)2						1.27	0.73
Funds flow from operations3						100.1	84.4
Basic per share ($/share)4						1.36	1.09
Diluted per share ($/share)4						1.31	1.05
Net income						15.4	11.9
Basic per share ($/share)						0.21	0.15
Diluted per share ($/share)						0.20	0.15
Capital expenditures						128.4	114.3
Decommissioning expenditures						6.6	10.1
Long-term debt						350.4	277.6
Net debt3						459.9	386.3
OPERATIONS
Daily Production
Light oil (bbl/d)						12,727	13,079
Heavy oil (bbl/d)						10,887	6,748
NGL (bbl/d)						3,072	2,783
Natural gas (mmcf/d)						70	70
Total production5 (boe/d)						38,416	34,238
Average sales price2,6
Light oil ($/bbl)						99.46	94.82
Heavy oil ($/bbl)						70.14	60.39
NGLs ($/bbl)						53.49	50.43
Natural gas ($/mcf)						2.18	2.38

Netback ($/boe)
Sales price							61.11		57.07
Risk management gain							0.78	1.24
Net sales price							61.89	58.31
Royalties							(8.22)	(7.05		)
Net operating costs4							(15.72)	(13.91		)
Transportation							(4.85)	(3.95		)
Netback4 ($/boe)							33.10	33.40

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 unaudited interim consolidated financial statements and management's discussion and analysis ("MD&A") as at and for the three month period ended March 31, 2025, on our website at www.obsidianenergy.com, which will also be filed on SEDAR+ and EDGAR in due course.

FIRST QUARTER 2025 OVERVIEW

Obsidian Energy continued with the strategy of holding our light oil production profile flat during the first quarter of 2025, while recycling capital into funding the development and exploration/appraisal of our Peace River play. Accordingly, average production of 38,416 boe/d for the first quarter of 2025 was in line with our expectations, and 12 percent above first quarter 2024 levels. Funds flow from operations ("FFO") increased by 19 percent (25 percent on a per share basis) to $100.1 million ($1.36 per share basic) for the quarter versus the same period in 2024, benefitting from increased production and higher realized sales prices.

Subsequent to the end of the first quarter, we closed the previously announced divestiture of our operated Pembina assets (the "Pembina Assets") to InPlay Oil Corp. ("InPlay") (collectively, the "Transaction"), while retaining our non-operated holdings in Pembina Cardium Unit #11. Proceeds on closing included cash of $211 million (after interim closing adjustments), 9.1 million shares in InPlay (post InPlay's recent 6:1 share consolidation), and $15 million associated with value received for InPlay's 34.6 percent working interest in the Willesden Green Cardium Unit #2 oil field. Cash proceeds were used to repay debt, resulting in approximately $30 million drawn on our $235 million syndicated credit facility post close.

"Our first quarter capital plan was heavily skewed towards an exploration/appraisal-based drilling program to both take advantage of areas within Peace River where we currently don't have all-season access, as well as to further delineate our land base," commented Stephen Loukas, Obsidian Energy's President and CEO. "Overall, we experienced constructive results with strong reservoir characteristics in five out of the seven pads tested early in the first quarter. Through the balance of this year, we will refine our technical work and well design to further improve production deliverability and returns. Most recently, we have experienced strong initial production results from our first half development-focused drilling in established areas that target both the Clearwater and Bluesky formations."

Stephen Loukas continued, "Over the last few months, uncertainty created by threats of broad-based tariffs from the U.S. has caused significant volatility in commodity prices, capital markets and equity valuations. The volatility in oil prices has been further exacerbated by the OPEC+ decision to increase production quotas. Given this environment, we are responding to the uncertainty by being prudent in our capital allocation. Accordingly, we have revised our first half 2025 capital program to reduce expenditures by opting to defer drilling in the Clearwater and Bluesky formations in Peace River that was initially planned for the second quarter. Moreover, should commodity prices not improve by the time spring break-up is over, we will significantly reduce our second half 2025 capital program to keep production flat at ~29,000 boe/d. Given the significant discount that we believe our shares trade to our intrinsic value, we will re-allocate capital to a combination of incremental stock repurchases and additional debt paydown until such time when commodity prices and development returns are supportive of resuming production growth. Lastly, with the closing of the sale of our Pembina Assets and the associated production, we are withdrawing our three-year growth plan to grow production to 50,000 boe/d in 2026 that was issued in September 2023. We currently plan to provide our second half 2025 guidance in late June."

2025 FIRST QUARTER CORPORATE HIGHLIGHTS

• Funds Flow - The Company generated FFO of $100.1 million ($1.36 per share basic) compared to $84.4 million ($1.09 per share basic) in the first quarter of 2024. Higher revenues from increased production levels resulted in higher FFO in 2025, which was partially offset by higher net operating and transportation costs as we continued to increase development and grow production in our Peace River area.

• Capital Development - First quarter capital expenditures totalled $128.4 million (2024 - $114.3 million) with six drilling rigs in operation, five of which were focused on exploration/appraisal and development activities in Peace River. Our abandonment program was also active during the quarter, with decommissioning expenditures of $6.6 million (2024 - $10.1 million).

• Share Buyback Program - A total of approximately 1.2 million shares were repurchased and cancelled under the Company's normal course issuer bid ("NCIB") for $9.6 million (at an average price of $8.29 per share) in the first quarter of 2025.

  • In February, the Company renewed our NCIB with the Toronto Stock Exchange, allowing for the purchase of up to 7,144,408 common shares over a period of 12 months from March 3, 2025, to March 2, 2026.

• Net Operating Costs - Net operating costs of $15.72 per boe in the first quarter of 2025 were higher than the corresponding period in 2024 ($13.91 per boe). Increased trucking costs due to higher than anticipated initial water volumes associated with our larger Peace River drilling program, additional repair and maintenance activity, and land survey costs required as part of the Pembina disposition contributed to this increase, which was partially offset by lower power costs.

• General and administrative ("G&A") Costs - G&A costs decreased to $1.61 per boe in the first quarter of 2025 compared to $1.77 per boe in 2024, largely due to our higher production base during 2025.

• Net Debt - Net debt levels were $459.9 million at March 31, 2025, compared to $411.7 million at December 31, 2024. Our active first quarter 2025 development program, which resulted in a higher working capital deficiency, contributed to this short-term increase.

  • Post Transaction close in April 2025, the cash proceeds were applied to the Company's syndicated credit facility, reducing our net debt by $211 million to approximately $250 million, excluding the value of our InPlay share position.

• Net Income - Net income for the first quarter of 2025 was $15.4 million ($0.21 per share basic) versus $11.9 million ($0.15 per share basic) in 2024. First quarter 2025 net income benefitted from increased production levels, which was partially offset by our higher net operating and transportation costs due to our larger production base and expanded operations in Peace River compared to the first quarter of 2024.

HIGHLIGHTS SUBSEQUENT TO FIRST QUARTER 2025

• Pembina Asset Transaction - On April 7, 2025, we closed our previously announced Pembina Asset disposition to InPlay. The Transaction has an effective date of December 1, 2024, and includes all the Company's assets in Pembina, except for our non-operated interest in the Pembina Cardium Unit #11.

• Semi-Annual Borrowing Base Redetermination - Obsidian Energy completed our semi-annual borrowing base redetermination upon closing the Transaction, which resulted in an aggregate amount available under our syndicated credit facility of $235.0 million. The revolving period and maturity dates under the syndicated credit facility were extended to May 31, 2026, and May 31, 2027, respectively. The Company used the cash proceeds from the Pembina disposition to reduce the amount outstanding under the syndicated credit facility to approximately $30 million.

• Senior Unsecured Notes - In light of market conditions, the Company was able to repurchase $2.0 million of our senior unsecured notes on the open market at a price of $1,027.50 per $1,000 principal amount, which was below the recent free cash flow offer price of $1,030 per $1,000 principal amount. Currently, we have $112.2 million of senior unsecured notes outstanding.

• Share Buyback Program - We repurchased and cancelled an additional approximate 2.3 million common shares at an average price of $6.34 share for total consideration of approximately $14.9 million under the NCIB up to May 6, 2025. In 2025, repurchases and cancellations total approximately 3.5 million common shares at an average price of $6.98 per share for total consideration of approximately $24.5 million.

  • Since the inception of the NCIB in 2023, we have re-purchased and cancelled a total of approximately 13.1 million common shares for total consideration of approximately $113.6 million.

2025 FIRST QUARTER CAPITAL PROGRAM

Weighted toward our Peace River heavy oil area, activities in the first half of 2025 to date focused on three distinct objectives:

1. Execute an early exploration/appraisal program for both the Clearwater and Bluesky formations to continue to appraise our land base, focused on areas with winter only access and seasonal testing limitations;

2. Prior to breakup, transition to development drilling in the established, all season access fields of Harmon Valley South ("HVS") (Bluesky formation) and Dawson (Clearwater formation) to increase production; and

3. Initiate an integrated waterflood pilot in the Clearwater formation to continue the development of the Dawson field. The Company drilled three producer wells and are currently drilling the first of two dedicated water injections wells for the project.

Our first half 2025 capital program utilized five rigs in Peace River drilling both development and exploration/appraisal wells in the Clearwater and Bluesky formations with a sixth rig to drill the four-well commitment in the Pembina area as part of the Transaction (costs included as part of interim closing adjustments). The breakdown of operated wells that were rig released and on production during the first quarter of 2025 are as follows:

			Q1 Gross (Net) Wells
			Rig Released			On Production
DEVELOPMENT WELLS
Heavy Oil Assets
Peace River (Bluesky)			11 (9.4	)		6 (5.0	)
Peace River (Clearwater)			4 (4.0	)		2 (2.0	)
Light Oil Assets
Pembina (Cardium)2			4 (4.0	)		4 (4.0	)
			19 (17.4	)		12 (10.9)1
EXPLORATION/APPRAISAL WELLS
Peace River (Bluesky)			3 (3.0	)		3 (3.0	)
Peace River (Clearwater)			4 (4.0	)		4 (4.0	)
			7 (7.0	)		7 (7.0	)
TOTAL OPERATED WELLS3			26 (24.4	)		19 (17.9)1

1. Three (3.0 net) wells placed on production in the first quarter of 2025 were rig released in 2024 and, which are included in the total.
2. Capital expenditures for the Pembina wells were paid for by InPlay as they were included in the interim closing adjustments of the Transaction.
3. Excluding injection or disposal wells.
4. In addition, Obsidian Energy participated in the rig release of five non-operated (2.2 net) wells in the first quarter of 2025.

HEAVY OIL ASSET HIGHLIGHTS

Exploration/Appraisal Program

A total of 7 (7.0 net) exploration/appraisal wells were drilled, rig released and placed on production in Peace River through a combination of whipstock wells with logs and/or core retrieval and a limited production test as winter access permitted. All seven exploration/appraisal wells showed encouraging results, encountering and producing oil, while five of the seven wells displayed strong preliminary tests.

• Nampa - Three (3.0 net) exploration/appraisal wells encountered solid reservoir with high-quality oil from three distinct sands, starting with the southern 9-06 Pad that targeted two individual sands in the upper Clearwater formation (previously untested by Obsidian Energy in the area). The deeper sand displayed a 30-day initial production ("IP") rate of 105 boe/d at 13.3^O API oil while the shallower sand produced at a 30-day IP rate of 74 boe/d at 11.6^O API oil.
  
  Additionally, a second well was drilled at the Nampa 7-34 Pad in the primary Clearwater reservoir, which produced at a 30-day IP rate of 128 boe/d at 15.9^O API oil and provided a delineation test for the seasonally restarted 6-28 Pad (previously released at a 30-day IP rate of 170 boe/d in 2024). The 6-28 Pad now has a prolonged production test at a 123-day IP rate of 118 boe/d. Both wells are shut in for seasonal access following testing.
  
  Throughout the Nampa field, early production results indicate potential for both primary stacked development and future enhanced oil recovery due to the relatively higher quality oil in this region.

• HVS - We drilled two (2.0 net) Bluesky formation exploration/appraisal wells testing the southern extent of our core Harmon Valley South field. Both wells encountered significant oil pay in this previously untested area with early results from truncated production tests, indicating economic potential in the field. The 15-15 Pad tested at a peak production rate of 151 boe/d with an improving 83 percent watercut prior to shut in; and the 10-27 Pad showed encouraging results with a pre-optimized improving peak rate of 69 boe/d at a 95 percent watercut despite a lower number of horizontal legs than standard (8 versus standard 11).

In total, we estimate that a minimum of 625 boe/d is currently shut in from these exploration/appraisal programs due to seasonal access. Economic evaluation of all season access construction and associated land acquisition is underway in all fields.

Development Program

We rig released 15 (13.4 net) operated development wells in Peace River and brought 8 (7.0 net) wells on production during the first quarter. With the majority of wells rig released late in the first quarter, a significant number of wells came on production towards the end of April with strong initial results.

• Dawson 4-23 Pad - Infill drilling continued with four (4.0 net) wells, all of which are currently on production utilizing simultaneous facilities construction and drilling operations to expediate timing of the wells coming onstream. The first two wells produced at a 30-day IP rate of 293 boe/d and 222 boe/d, respectively. The second two wells were brought onstream and are exhibiting steadily improving oil rates.

• HVS - We drilled five (5.0 net) follow up wells following the success of the first wells on our 13-08 and 13-18 Pads in 2024 (30-day IP rates of 448 and 503 boe/d, respectively). Two of the five wells further test our "waffle well" drilling design, which has shown successful results in increasing oil recovery on existing Pads. All five wells are currently on production; the well with the longest production history is on the 13-08 Pad, which had a 16-day production rate of 424 boe/d.

• Walrus 7-21 Pad - Two wells (one earning, referenced below) came on production in mid-April and are in the process of cleaning up.

• Land Farm-In Earning Wells - Four (2.6 net) wells were drilled in HVS and East Seal as part of earning or joint venture land agreements to further delineate new areas of Peace River. The first of two (1.3 net) wells from our East Seal 4-14 Pad farm-in averaged a 30-day IP rate of 259 gross boe/d. The second well is shut in and slated to come on production after break-up when access improves. In the southern part of our HVS field, the first of two (1.3 net) wells at the 16-09 Pad produced at a 27-day IP of 138 gross boe/d, while the second well is in the process of cleaning up.

In April and early May, we brought an additional 12 (11.5 net) operated and four (1.8 net) non-operated wells onstream, bringing the total operated wells on production to date to 35 (31.2 net) (including three (3.0 net) wells from our 2024 program). The remaining wells drilled from our first half 2025 program are expected to be on production by the end of June.

Waterflood Pilot Project

The Company began drilling a new Clearwater waterflood pilot in the middle of our Peace River Dawson field at the 4-24 Pad that includes three (3 net) producer and two (2 net) single leg injector wells. The five-well waterflood pilot design mimics successful peer waterflood patterns in analogous industry fields and will be the first Obsidian Energy integrated Clearwater waterflood pilot in the Peace River area.

• We plan to temporarily produce the injectors prior to water injection to evaluate reservoir characteristics. The first two producing wells on the pad came on production on April 27, 2025, and the remaining wells are expected to come onstream following the completion of drilling operations utilizing SIMOPS¹.

LIGHT OIL ASSETS HIGHLIGHTS

Development activity for the first quarter of 2025 was focused in the Pembina (Cardium) area to drill the four (4.0 net) well commitment as part of the Transaction; all drilling and associated costs were included in the interim closing adjustments at InPlay's expense. All rights for the wells and associated infrastructure assets were transferred to InPlay upon the Transaction close on April 7.

UPDATED GUIDANCE

Revised H1 2025 Capital and Operating Program

As a result of the volatile commodity price environment the Company has decided not to drill a portion of our first half program that utilized three rigs in the second quarter to drill through breakup in Peace River. Peace River development has now been reduced to one rig drilling the integrated waterflood pilot well at our Dawson Clearwater field. Completion activities are continuing during the second quarter as we bring wells on production that were drilled in our first quarter program.

The revised breakdown of operated wells expected to be rig released during the first half of 2025 is as follows:

			H1 2025 Gross (Net) Wells			Revised H1 2025 Gross (Net) Wells
DEVELOPMENT WELLS
Heavy Oil Assets
Peace River (Bluesky)			13 (11.4	)		12 (10.4	)
Peace River (Clearwater)			14 (14.0	)		7 (7.0	)
Light Oil Assets
Pembina (Cardium)1			4 (4.0	)		4 (4.0	)
			31 (29.4	)		23 (21.4	)
EXPLORATION/APPRAISAL WELLS
Peace River (Bluesky)			3 (3.0	)		3 (3.0	)
Peace River (Clearwater)			4 (4.0	)		4 (4.0	)
			7 (7.0	)		7 (7.0	)
TOTAL OPERATED WELLS2,3			38 (36.4	)		30 (28.4	)

1. Capital expenditures for the Pembina wells were paid for by InPlay as they were included in the interim closing adjustments of the Transaction.
2. Excluding injection or disposal wells.
3. In addition, Obsidian Energy expects to participate in a total of five non-operated (2.2 net) wells in the first half of 2025.

As a result of the decision to not drill some of our first half activity, we have revised our first half 2025 guidance below.

		H1 2025 Guidance		Revised H1 2025E Guidance		Q2 2025E
Production1	boe/d	33,300 - 34,300		33,600 - 34,000		28,800 - 29,600
% Oil and NGLs	%	72		71		72
Capital expenditures2	$ millions	185 - 195		165 - 170		37 - 42
Decommissioning expenditures	$ millions	11 - 12		11 - 12		4 - 5
Net operating costs3	$/boe	14.15 - 14.60		14.74 - 14.90		13.50 - 13.85
General & administrative	$/boe	1.75 - 1.85		1.78 - 1.82		2.00 - 2.10
Based on midpoint of above guidance
FFO3,5	$ millions	180		160		60
FFO/share6	$/share	2.44		2.23		0.86
FCF3,5	$ millions	(22)		(19)		16
FCF/share6	$/share	(0.29)		(0.27)		0.23
Net debt (prior to NCIB)7	$ millions	240		255		255
Annualized net debt (prior to NCIB) to FFO7	times	0.7		0.8		1.1

Pricing assumptions
WTI (May - June)4	US$/bbl	71.00		60.00		60.00
MSW Differential (June)4	US$/bbl	5.00		2.00		2.00
WCS Differential (June)4	US$/bbl	14.00		10.00		10.00
AECO (May - June)4	$/GJ	2.00		2.00		2.00

Asset level information, based on midpoint of above guidance		H1 2025 Guidance	Revised H1 2025E Guidance	Q2 2025E
Heavy Oil
Average production	Boe/d	12,900	12,300	13,000
Capital expenditures2	$ millions	142	123	27
Net operating costs3	$/boe	17.25	19.25	18.85
Netback3	$/boe	34.00	26.25	22.10
Net operating income3	$ millions	80	60	26
Asset level FCF	$ millions	(62)	(63)	(1)
Light Oil
Average production	Boe/d	20,900	21,500	16,200
Capital expenditures2	$ millions	45	43	12
Net operating costs3	$/boe	12.35	12.35	9.60
Netback3	$/boe	31.50	30.50	26.45
Net operating income3	$ millions	120	120	38
Asset level FCF	$ millions	75	77	26

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. Approximate mid-point of revised guidance range: 9,730 bbl/d light oil, 11,600 bbl/d heavy oil, 2,590 bbl/d NGLs and 59.3 mmcf/d natural gas. Average production volumes include a minimal amount of forecasted production associated with exploration/appraisal capital expenditures. First half and second quarter 2025E includes approximately 6,060 boe/d and 850 boe/d of production (field estimates), respectively, associated with the Pembina Asset disposition.
2. Capital expenditures included approximately $34 million for Peace River exploration/appraisal and enhanced oil recovery waterflood activities with minimal impact on forecasted production volumes. Asset level capital did not include $3 million in corporate capital. Revised capital expenditures include approximately $28 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 $2 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 were for the first half of 2025 and included 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 forecasted for March to June 30, 2025. H1 2025E pricing assumptions, including actuals realized from January 1, 2025, to February 18, 2025, resulted 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.
   
   Revised first half 2025 pricing assumptions include risk management (hedging) adjustments as of May 1, 2025. WTI and AECO pricing as well as MSW and WCS differentials assumptions for the first half 2025E are forecasted for May to June 30, 2025. H1 2025E pricing assumptions, including actuals realized from January 1, 2025, to April 30, 2025, result in WTI of US$66.20/bbl, MSW differentials of US$4.05/bbl, WCS differentials of US$11.62/bbl, AECO of $2.01/GJ, and FX of 1.41x CAD/USD.
5. FFO and FCF included 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 was based on a share price of $7.66 per share. Revised FFO and FCF include approximately $3 million of estimated gain 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 $6.48 per share
6. Per share calculations were based on an estimated 73.7 million weighted average shares outstanding for the six months ended June 30, 2025. Revised per share calculations are based on an estimated 71.8 million weighted average shares outstanding for the six months ended June 30, 2025.
7. Net debt figures were estimated as at June 30, 2025. Revised net debt figures did not include the impact of the 9.1 million InPlay Oil Corp. common shares, which were received as part of the Transaction, valued at $60.0 million as calculated with May 5, 2025, closing price of $6.57. If included, net debt would be reduced to $195 million with a 0.8x net debt (prior to NCIB) to FFO ratio.

Guidance Sensitivity Table
Variable	Range	Change in Q2 2025E FFO ($ millions)
WTI (US$/bbl)	+/- $1.00/bbl	1.2
MSW light oil differential (US$/bbl)	+/- $1.00/bbl	0.1
WCS heavy oil differential (US$/bbl)	+/- $1.00/bbl	0.2
Change in AECO ($/GJ)	+/- $0.25/GJ	0.3

HEDGING UPDATE

In the first quarter of 2025, the Company's hedging activities led to a realized gain of $2.7 million, primarily related to our natural gas contracts. The following contracts are in place for 2025 on a weighted average basis:

Oil Contracts

Type	Remaining Term	Volume (bbl/d)	Swap Price (C$/bbl)
WTI Swap	April 2025	5,750	$98.78
WTI Swap	May 2025	3,750	$92.80
WTI Collar	April 2025	3,500	$95.00 - $99.00
WTI Collar	May 2025	3,500	$97.29 - $101.79
WCS Differential	April 2025 - June 2025	8,500	($19.39)
WCS Differential	July 2025 - September 2025	7,750	($18.83)
WCS Differential	October 2025 - December 2025	6,000	($19.30)
WSW Differential	April 2025 - June 2025	1,500	($7.90)
MSW Differential	July 2025 - September 2025	500	($6.59)

AECO Natural Gas Contracts

Type	Remaining Term	Volume (mcf/d)	Swap Price (C$/mcf)
AECO Swap	April 2025	17,062	$2.24
AECO Swap	May - October 2025	19,905	$2.26
AECO Collar	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.

ANNUAL AND SPECIAL MEETING

The Company's Annual and Special Meeting (the "Meeting") is scheduled for Wednesday, May 7, 2025, at 1:00 p.m. MT (3:00 p.m. ET) at the offices of Obsidian Energy, Suite 200, 207 - 9 Avenue SW, Calgary, Alberta. Access to the Meeting will, subject to Company's by-laws, be limited to essential personnel, registered shareholders and proxyholders entitled to attend and vote at the Meeting as well as invited guests. Additional information about the Meeting can be found on our website.

In association with the Meeting, our President and CEO, Stephen Loukas and other members of management will host a webcast presentation after the formal portion of the meeting at 2:00 p.m. MT (4:00 pm ET) (the "Presentation").

The Presentation will be broadcast live on the Internet and may be accessed either through our website or directly at the webcast portal. Those who wish to listen to the Presentation should connect at least five to 10 minutes prior to the scheduled start time through the following numbers:

Canada/U.S.:		1-844-763-8274 (toll-free)
International:		1-647-484-8814

A question-and-answer session will be held following the Presentation. If you wish to submit a question to the Company, participants can do so ahead of time after registering on the webcast portal on the Intranet or by emailing questions to [e-mail]. An updated corporate presentation and the Presentation will be available following the webcast on our website.

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.

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 interim consolidated financial statements and MD&A as at and for three months ended March 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 three-month period ended March 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 three months ended March 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 three months ended March 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 March 31
(millions)										2025				2024
Cash flow from operating activities										$		96.7		$	58.7
Change in non-cash working capital												(5.8	)		13.4
Decommissioning expenditures												6.6			10.1
Onerous office lease settlements												0.7			2.3
Deferred financing costs												(0.4	)		(0.6	)
Restructuring												0.1			-
Transaction costs												2.2			-
Other expenses												-			0.5
Funds flow from operations												100.1			84.4
Capital expenditures												(128.4	)		(114.3	)
Decommissioning expenditures												(6.6	)		(10.1	)
Free cash flow										$		(34.9	)	$	(40.0	)

Netback to Sales Price

										Three months ended March 31
(millions)										2025				2024
Sales price										$		211.3		$	177.8
Risk management gain												2.7			3.8
Net sales price												214.0			181.6
Royalties												(28.4	)		(22.0	)
Net operating costs												(54.4	)		(43.2	)
Transportation												(16.8	)		(12.3	)
Netback										$		114.4		$	104.1

Net Operating Costs to Operating Costs

										Three months ended March 31
(millions)										2025				2024
Operating costs										$		59.0		$	49.3
Less processing fees												(2.8	)		(3.9	)
Less road use recoveries												(1.8	)		(2.1	)
Less realized power risk management loss												-			(0.1	)
Net operating costs										$		54.4		$	43.2

Net Debt to Long-Term Debt

						As at
						March 31
(millions)						2025					2024
Long-term debt
Syndicated credit facility							$		239.5		$	167.5
Senior unsecured notes									114.2			114.2
Unamortized discount of senior unsecured notes									(1.0	)		(1.5	)
Deferred financing costs									(2.3	)		(2.6	)
Total									350.4			277.6
Working capital deficiency
Cash									(0.3	)		(0.3	)
Accounts receivable									(86.0	)		(83.2	)
Prepaid expenses and other									(15.2	)		(14.3	)
Accounts payable and accrued liabilities									211.0			206.5
Total									109.5			108.7
Net debt							$		459.9		$	386.3

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; how we expect to improve production deliverability and returns; our expectations for second half 2025 capital program to keep production flat if commodity prices do not improve by spring break-up; when we plan to issue second half 2025 guidance; how we plan to re-allocate capital if the commodity price and development returns are not supportive of production growth; our revised expectations for the first half 2025 drilling program and capital expenditures; our development and production expectations in the Peace River area; our expectations for on production and onstream dates; our expectations in connection with the Clearwater injector pilot in the Peace River Dawson field; our expectations for production that is shut-in due to seasonal access; our revised first half and second quarter 2025 guidance for production, production mix, capital and decommissioning expenditures, net operating and G&A costs, FFO, FFO/share, FCF, FCF/share, net debt (prior to NCIB, and annualized net debt (prior to NCIB) to FFO; our revised guidance for asset level average production, capital expenditures, net operating costs, netbacks, net operation income and the asset level FCF; our guidance sensitivities; our hedges; and the timing of our updated corporate presentation and Meeting and Presentation.

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.

The future acquisition by the Company of the Company's common shares pursuant to its share buyback program (including through an 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 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 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; 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: [phone]
Toll Free: 1-866-693-2707
Website: www.obsidianenergy.com;

Investor Relations:
Toll Free: 1-888-770-2633
E-mail: [e-mail]

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¹ SIMOPS, or Simultaneous Operations, refers to when multiple work activities, potentially involving different groups or under different management systems, are carried out simultaneously in the same area.

To view the source version of this press release, please visit https://www.newsfilecorp.com/release/251091

SOURCE: Obsidian Energy Ltd.