TOURMALINE DELIVERS RECORD PRODUCTION IN Q1 2025, ANNOUNCES TWO ACQUISITIONS AND DECLARES A SPECIAL DIVIDEND

CALGARY, AB, May 7, 2025 /CNW/ - Tourmaline Oil Corp. (TSX: TOU) ("Tourmaline" or the "Company") is pleased to release financial and operating results for the first quarter of 2025, announce two acquisitions in the NEBC Montney and declare a special dividend.

HIGHLIGHTS

• First quarter 2025 average production was 637,867 boepd, an 8% increase over first quarter 2024 and ahead of the 630,000 – 635,000 boepd first quarter 2025 expected range announced on March 5, 2025.
• First quarter 2025 cash flow⁽¹⁾ ("CF") was $963.0 million ($2.56 per diluted share⁽²⁾) on total capital expenditures⁽³⁾ of $825.0 million (EP spending⁽⁴⁾ of $797.7 million) generating free cash flow⁽⁵⁾ ("FCF") of $149.1 million for the quarter ($0.40 per diluted share⁽⁶⁾).
• In 2025, at strip pricing⁽⁷⁾, the Company now expects to generate CF of $3.9 billion ($10.44 per diluted share) and FCF of $960.0 million ($2.55 per diluted share) on EP spending of $2.725 billion (midpoint of 2025 guidance range).
• Tourmaline continues to consolidate the NEBC Montney, one of the most profitable gas plays in North America, in concert with the Company's NEBC infrastructure buildout. In the North Montney, the Company has entered into an agreement to acquire the balance of the jointly-owned Laprise-Conroy assets through the acquisition of Saguaro Resources Ltd. In addition, Tourmaline has entered into an agreement to acquire assets located in the Greater Septimus area of the South Montney. The Company expects these acquisitions to close in Q2 2025.
• Tourmaline's Board of Directors has declared a special dividend of $0.35 per share payable on May 26, 2025 to shareholders of record on May 15, 2025.
• The Company intends to declare a quarterly dividend of $0.50 per share, payable on June 30, 2025, to shareholders of record on June 16, 2025.

PRODUCTION UPDATE

• First quarter 2025 average production was 637,867 boepd, slightly ahead of the guidance range announced on March 5, 2025 and up 8% from the first quarter of 2024. March 2025 average production was 645,036 boepd.
• First quarter 2025 average liquids production (oil, condensate, NGLs) was 147,438 bpd, up 2% over the first quarter 2024 average liquids production of 145,016 bpd.
• The 2025 forecast production range of 635,000 - 665,000 boepd remains unchanged. Production averaged 660,000 boepd for the first half of April.
• The Company expects second quarter 2025 average production in the 615,000 - 625,000 boepd range, reflecting increased maintenance now scheduled given the anticipated weaker gas prices during that time period, particularly at Station 2 where pricing and volume in April was impacted by maintenance at the third party-operated Aitken storage facility.

FINANCIAL RESULTS

• First quarter 2025 cash flow was $963.0 million ($2.56 per fully diluted share) and FCF was $149.1 million ($0.40 per fully diluted share).
• First quarter 2025 earnings were $212.7 million ($0.56 per fully diluted share).
• First quarter EP capital spending was $797.7 million.  The Company expects EP capital spending to be approximately $560.0 million in Q2 2025 during spring break-up, yielding an estimated 1H 2025 FCF of $430.0 million ($1.14 per diluted share) based on strip pricing. The Company expects commodity prices to improve in the 2H 2025 with the start-up of the LNG Canada facility on the West Coast, resulting in higher FCF in 2H 2025 relative to 1H 2025.

2025 CAPITAL PROGRAM

• The full year 2025 EP capital program remains unchanged at $2.60 to $2.85 billion.
• Given weak Station 2 gas prices, the Company intends to defer some planned Q2 frac activity into the third quarter of 2025. The Company continues to expect stronger prices at both the Station 2 and AECO hubs during the second half of 2025 as gas volumes commence flowing west to the LNG Canada liquification facility. The Company will continue to match planned production growth to the anticipated increasing natural gas price curve.
• The Company expects to release an updated multi-year EP plan, including the full NEBC Montney gas and liquids infrastructure buildout, and incorporation of all recent acquisitions in the second half of 2025.  Inclusive of projects not yet incorporated in the EP plan and recent acquisitions, the Company forecasts to enter the next decade producing at approximately 850,000 boepd⁽⁸⁾.

ACQUISITION UPDATE

• Tourmaline continues to consolidate the NEBC Montney, one of the most profitable gas plays in North America, in concert with the Company's NEBC infrastructure buildout.
• In the North Montney, the Company has entered into an agreement to acquire the balance of the jointly-owned Laprise-Conroy assets through the acquisition of Saguaro Resources Ltd., and in the South Montney, Tourmaline has entered into an agreement to acquire assets in the Greater Septimus area from a third party.  Both transactions are expected to close in Q2 2025, and Tourmaline's forward guidance and EP plan will reflect these acquisitions in the Company's next update.
• In aggregate, these two transactions add approximately 20,000 boepd of current production, an estimated 369.4 mmboe of current 2P reserves⁽⁹⁾, and approximately 410 primarily Tier 1 future net drilling locations.  Production and reserves from these assets are expected to experience significant future growth as each asset is systematically developed as part of the Company's NEBC Montney buildout.
• The Laprise-Conroy asset is the key component of the North Montney Phase 2 project, and the Greater Septimus asset is complementary and adjacent to Tourmaline's planned Groundbirch 400 mmcfpd / 20,000 bpd two-phase gas plant development project.
• As part of these transactions, Tourmaline will also acquire 9 net sections and an estimated 54 net drilling locations in the Resthaven area of the Alberta Deep Basin.
• Tourmaline will issue a total of approximately 13 million common shares as consideration for the two transactions, leaving the balance sheet in a very strong position for potential further asset acquisitions going forward. The final number of shares to be issued pursuant to these acquisitions will be determined at the closing of the transactions based on the price of Tourmaline common shares leading up to the respective closing dates.

MARKETING UPDATE

• Tourmaline's average realized natural gas price in the first quarter of 2025 was CAD $4.30/mcf, meaningfully (CAD $2.11/mcf) above the AECO 5A benchmark price of CAD $2.19/mcf over the same time period, as the Company continues to benefit from its diversification portfolio and strategic hedging program. 
• From Q2 to Q4 2025, Tourmaline will average 2.1 bcfpd of natural gas sales that are not exposed to floating local market prices (AECO and Station 2).
• Tourmaline has an average of 1.16 bcfpd hedged in 2025 at a weighted average fixed price of CAD $4.95/mcf. This includes 72 mmcfpd hedged at a weighted average price of CAD $20.76/mcf in international markets and 156 mmcfpd at a weighted average price of CAD $6.68/mcf in Western US markets.
• The Company is highly encouraged by the growing demand-driven natural gas price outlook in North America, including the Western Canadian gas trading hubs. The Company's EP and acquisition activities are guided by this strong multi-year price outlook; however, Tourmaline continues to remain disciplined to not oversupply local hubs. The natural gas growth achieved by the Company in 2023-24 was primarily matched with new export contracts out of the Western Canadian Sedimentary Basin, including 95 mmcfpd that will flow to the Gulf Coast in November of this year. 

EP UPDATE

• First quarter 2025 EP activity was highlighted by a series of pads in NEBC that are well ahead of performance type curve thus far.  At Sunrise in the South Montney, the 4 well pad produced at average per well 30-day IP rates of 7.2 mmcfpd and 218 bbls/day of condensate.  At Groundbirch, the 6 wells on the 4-17 well pad have average 30-day IP rates of 10.4 mmcfpd at a flowing casing pressure of 11.9 MPa.  At Gundy in the North Montney, the 7 wells on the C-2-G pad have average 30-day IP rates of 8.4 mmcfpd and 128 bbls/day of condensate. At Aitken, the 4 wells on the C-100-C pad have averaged 8.2 mmcfpd with 169 bbls/day of condensate over the first 22 days of production.
• The strong 2024 well performance in the Alberta Deep Basin continued in the first quarter of 2025 with record March average production of 330,000 boepd. Strong pads ahead of performance curves were delivered across the entire complex, including at Hanlan (6-29 pad), Lambert-Minehead and Kakwa (3-28 pad).
• The Company plans to drill a total of 364 net wells in 2025, including 169 wells in the Alberta Deep Basin, 159 wells in the NEBC gas condensate complex, and 36 wells on the Peace River High.
• Notable exploration successes were realized in the South Deep Basin.  At Willesden Green, the Company's initial Belly River well tested at over 700 bblpd of wellhead liquids (<1% water cut) plus approximately 1.0 mmcfpd of natural gas.  In the down-dip high pressure Glauconite play, several new successful wells were brought on-stream. The Company is optimistic on the new incremental drilling inventory associated with both of these South Deep Basin successes.

DIVIDENDS

• Tourmaline's Board of Directors has declared a special dividend of $0.35 per share, payable on May 26, 2025 to shareholders of record on May 15, 2025.
• The Company intends to declare the quarterly base dividend of $0.50 per share in early June, which will be payable on June 30, 2025 to shareholders of record at the close of business on June 16, 2025. The special dividend is, and the quarterly base dividend will be, designated as an eligible dividend for Canadian income tax purposes.

____________________
(1)	This news release contains certain specified financial measures consisting of non-GAAP financial measures, non-GAAP financial ratios, capital management measures and supplementary financial measures. See "Non-GAAP and Other Financial Measures" in this news release for information regarding the following specified financial measures: "cash flow", "capital expenditures", "EP spending", "free cash flow", "operating netback", "operating netback per boe", "cash flow per diluted share", "free cash flow per diluted share", "adjusted working capital" and "net debt". Since these specified financial measures do not have standardized meanings under International Financial Reporting Standards ("GAAP"), securities regulations require that, among other things, they be identified, defined, qualified and, where required, reconciled with their nearest GAAP measure and compared to the prior period. See "Non-GAAP and Other Financial Measures" in this news release and in the Company's most recently filed Management's Discussion and Analysis (the "Q1 MD&A"), which information is incorporated by reference into this news release, for further information on the composition of and, where required, reconciliation of these measures.
(2)	"Cash flow per diluted share" is a non-GAAP financial ratio. Cash flow, a non-GAAP financial measure, is used as a component of the non-GAAP financial ratio. See "Non-GAAP and Other Financial Measures" in this news release and in the Q1 MD&A.
(3)	"Capital expenditures" is a non-GAAP financial measure defined as cash flow used in investing activities adjusted for the change in non-cash working capital (deficit). See "Non-GAAP and Other Financial Measures" in this news release and in the Q1 MD&A.
(4)	"EP spending" (or "Exploration and production expenditures") is a non-GAAP financial measure defined as capital expenditures, excluding property acquisitions and dispositions and other expenditures. See "Non-GAAP and Other Financial Measures" in this news release.
(5)	"Free cash flow" is a non-GAAP financial measure defined as cash flow less capital expenditures, excluding acquisitions and dispositions. Free cash flow is prior to dividend payments. See "Non-GAAP and Other Financial Measures" in this news release.
(6)	"Free cash flow per diluted share" is a non-GAAP financial ratio. Free cash flow, a non-GAAP financial measure, is used as a component of the non-GAAP financial ratio. See "Non-GAAP and Other Financial Measures" in this news release and in the Q1 MD&A.
(7)	Based on oil and gas commodity strip pricing at April 15, 2025.
(8)	Forecasted production of 850,000 boepd is indicative and provided for illustration only and is based on budgets and forecasts that have not been finalized and is subject to a variety of contingencies including prior years' results and to the expectations, assumptions, risks and uncertainties described under "Forward-Looking Information". Additional information will be provided with the Company's updated multi-year EP plan, expected to be released in 2H 2025.
(9)	Reserves have been internally estimated by qualified reserve evaluators in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities and the Canadian Oil and Gas Evaluation Handbook with an effective date of January 1, 2025 for Saguaro and April 1, 2025 for the Greater Septimus assets.

CORPORATE SUMMARY – FIRST QUARTER 2025

					Three Months Ended March 31,
					2025	2024	Change
OPERATIONS
Production
Natural gas (mcf/d)					2,942,574	2,682,364	10 %
Crude oil, condensate and NGL (bbl/d)					147,438	145,016	2 %
Oil equivalent (boe/d)					637,867	592,077	8 %
Product prices^(1)
Natural gas ($/mcf)					$                4.30	$                3.77	14 %
Crude oil, condensate and NGL ($/bbl)					$              56.75	$              53.53	6 %
Operating expenses ($/boe)					$                5.15	$                4.81	7 %
Transportation costs ($/boe)					$                5.53	$                5.23	6 %
Operating netback ($/boe)^(2)					$              19.15	$              17.35	10 %
Cash general and administrative expenses ($/boe)^(3)					$                0.82	$                0.76	8 %
FINANCIAL ($000, except share and per share)
Commodity sales from production					1,457,567	1,474,379	(1) %
Total revenue from commodity sales and realized gains					1,891,593	1,626,169	16 %
Royalties					179,159	150,471	19 %
Cash flow					963,046	871,144	11 %
Cash flow per share (diluted)					$                2.56	$                2.45	4 %
Net earnings					212,678	244,874	(13) %
Net earnings per share (diluted)					$                0.56	$                0.69	(19) %
Capital expenditures (net of dispositions)^(2)					825,018	556,245	48 %
Weighted average shares outstanding (diluted)					376,842,319	354,893,800	6 %
Net debt					(1,842,439)	(1,694,906)	9 %

Notes:
(1)	Product prices include premiums and losses on risk management activities and financial instrument contracts.
(2)	See "Non-GAAP and Other Financial Measures" in this news release and in the Q1 2025 MD&A.
(3)	Excluding interest and financing charges.

Conference Call Tomorrow at 9:00 a.m. MT (11:00 a.m. ET)

Tourmaline will host a conference call tomorrow, May 8, 2025, starting at 9:00 a.m. MT (11:00 a.m. ET).

To participate without operator assistance, you may register and enter your phone number at https://emportal.ink/41TmpoT to receive an instant automated call back.

To participate using an operator, please dial 1-888-510-2154 (toll-free in North America), or 1-416-900-0527 (international dial-in), a few minutes prior to the conference call.

REPLAY DETAILS

If you are unable to dial into the live conference call on May 8, 2025, a replay will be available by dialing 1-888-660-6345 (international 1-289-819-1450), referencing Encore Replay Code 08772. The recording will expire on May 22, 2025.

Reader Advisories

CURRENCY

All amounts in this news release are stated in Canadian dollars unless otherwise specified.

FORWARD-LOOKING INFORMATION

This news release contains forward-looking information and statements (collectively, "forward-looking information") within the meaning of applicable securities laws. The use of any of the words "forecast", "expect", "anticipate", "continue", "estimate", "objective", "ongoing", "on track", "may", "will", "project", "should", "believe", "plans", "intends" and similar expressions are intended to identify forward-looking information. More particularly and without limitation, this news release contains forward-looking information concerning Tourmaline's plans and other aspects of its anticipated future operations, management focus, objectives, strategies, financial, operating and production results and business opportunities, including the following: the future declaration and payment of base and special dividends and the timing and amount thereof which assumes, among other things, the availability of free cash flow to fund such dividends; anticipated cash flow and free cash flow levels; anticipated liquids and natural gas production and production growth for various periods including estimated production levels; expected full-year 2025 EP capital budget; anticipated natural gas prices and demand growth outlooks; the timing for the release of updated guidance and an updated EP plan; the completion of the acquisitions described in this news release including the timing and terms thereof and the anticipated benefits to be derived therefrom including the anticipated number of shares to be issued in connection with such acquisitions; as well as Tourmaline's future drilling prospects and plans, business strategy, future development and growth opportunities, prospects and asset base.  The forward-looking information is based on certain key expectations and assumptions made by Tourmaline, including expectations and assumptions concerning the following: prevailing and future commodity prices and currency exchange rates; the degree to which Tourmaline's operations and production may be disrupted or by circumstances attributable to supply chain disruptions; applicable royalty rates and tax laws; interest rates; inflation rates; future well production rates and reserve volumes; operating costs, receipt of regulatory approvals and the timing thereof (including with respect to the acquisitions described in this news release); the performance of existing and future wells; the success obtained in drilling new wells; anticipated timing and results of capital expenditures; the sufficiency of budgeted capital expenditures in carrying out planned activities; the timing, location and extent of future drilling operations; the benefits to be derived from acquisitions (including the acquisitions described in this news release); the state of the economy and the exploration and production business; the availability and cost of financing, labour and services; ability to maintain investment grade credit rating; and ability to market crude oil, natural gas and natural gas liquids successfully. Without limitation of the foregoing, future dividend payments, if any, and the level thereof is uncertain, as the Company's dividend policy and the funds available for the payment of dividends from time to time is dependent upon, among other things, free cash flow, financial requirements for the Company's operations and the execution of its growth strategy, fluctuations in working capital and the timing and amount of capital expenditures, debt service requirements and other factors beyond the Company's control. Further, the ability of Tourmaline to pay dividends is subject to applicable laws (including the satisfaction of the solvency test contained in applicable corporate legislation) and contractual restrictions contained in the instruments governing its indebtedness, including its credit facility.

Statements relating to "reserves" are also deemed to be forward looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.

Although Tourmaline believes that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Tourmaline can give no assurances that it will prove to be correct. Since forward-looking information addresses future events and conditions, by its very nature it involves inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to: the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; supply chain disruptions; the uncertainty of estimates and projections relating to reserves, production, revenues, costs and expenses; health, safety and environmental risks; commodity price and exchange rate fluctuations; interest rate fluctuations; changes in rates of inflation; marketing and transportation; loss of markets; environmental risks; competition; incorrect assessment of the value of acquisitions; failure to complete or realize the anticipated benefits of acquisitions or dispositions; stock market volatility; ability to access sufficient capital from internal and external sources; uncertainties associated with counterparty credit risk; failure to obtain required regulatory and other approvals including drilling permits and the impact of not receiving such approvals on the Company's long-term planning; climate change risks; severe weather (including wildfires and drought); risks of wars or other hostilities or geopolitical events, civil insurrection and pandemics; risks relating to Indigenous land claims and duty to consult; data breaches and cyber attacks; risks relating to the use of artificial intelligence; changes in legislation, including but not limited to tax laws, royalties and environmental regulations (including greenhouse gas emission reduction requirements and other decarbonization or social policies) and including uncertainty with respect to the interpretation of omnibus Bill C-59 and the related amendments to the Competition Act (Canada)); trade policy, barriers, disputes or wars (including new tariffs or changes to existing international trade arrangements); general economic and business conditions and markets. Readers are cautioned that the foregoing list of factors is not exhaustive.

Additional information on these and other factors that could affect Tourmaline, or its operations or financial results, are included in the Company's most recently filed  Management's Discussion and Analysis (See "Forward-Looking Statements" therein), Annual Information Form (See "Risk Factors" and "Forward-Looking Statements" therein) and other reports on file with applicable securities regulatory authorities which may be accessed through the SEDAR+ website (www.sedarplus.ca) or Tourmaline's website (www.tourmaline.com).

The forward-looking information contained in this news release is made as of the date hereof and Tourmaline undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless expressly required by applicable securities laws.

RESERVES DATA

The reserves data set forth in this new release is based upon internal estimates. There are numerous uncertainties inherent in estimating quantities of crude oil, natural gas and NGL reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth above are estimates only. In general, estimates of economically recoverable crude oil, natural gas and NGL reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially. For those reasons, estimates of the economically recoverable crude oil, NGL and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary. The Company's actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material.

BOE EQUIVALENCY

In this news release, production and reserves information may be presented on a "barrel of oil equivalent" or "BOE" basis. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In addition, as the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

FINANCIAL OUTLOOKS

Also included in this news release are estimates of Tourmaline's 2025 cash flow and free cash flow, which are based on, among other things, the various assumptions as to production levels, capital expenditures and other assumptions disclosed in this news release and including Tourmaline's estimated 2025 average production of 635,000 – 665,000 boepd, 2025 commodity price assumptions for natural gas ($3.78/mmbtu NYMEX US,  $2.58/mcf AECO, $12.60/mcf JKM US), crude oil ($62.72/bbl WTI US) and an exchange rate assumption (CAD/USD) of $0.71. These estimates are included to provide readers with an understanding of Tourmaline's anticipated cash flow and free cash flow based on the capital expenditure, production, pricing, exchange rate and other assumptions described herein and readers are cautioned that the information may not be appropriate for other purposes.

NON-GAAP AND OTHER FINANCIAL MEASURES

This news release contains the terms "cash flow", "capital expenditures", "EP spending", "free cash flow", and "operating netback", which are considered "non-GAAP financial measures" and the terms "cash flow per diluted share", "free cash flow per diluted share", "operating netback per boe", and "cash flow per-boe", which are considered "non-GAAP financial ratios". These terms do not have a standardized meaning prescribed by GAAP. In addition, this news release contains the terms "adjusted working capital" and "net debt", which are considered "capital management measures" and do not have standardized meanings prescribed by GAAP. Accordingly, the Company's use of these terms may not be comparable to similarly defined measures presented by other companies. Investors are cautioned that these measures should not be construed as an alternative to or more meaningful than the most directly comparable GAAP measures in evaluating the Company's performance. See "Non-GAAP and Other Financial Measures" in the most recent Management's Discussion and Analysis for more information on the definition and description of these terms.

Non-GAAP Financial Measures

Cash Flow

Management uses the term "cash flow" for its own performance measure and to provide shareholders and potential investors with a measurement of the Company's efficiency and its ability to generate the cash (net of current income taxes) necessary to fund its future growth expenditures, to repay debt or to pay dividends. The most directly comparable GAAP measure for cash flow is cash flow from operating activities. A summary of the reconciliation of cash flow from operating activities to cash flow, is set forth below:

			Three Months Ended March 31,
(000s)			2025	2024
Cash flow from operating activities (per GAAP)			$ 1,088,311	$    640,617
Current income taxes			(37,882)	(31,658)
Current income taxes paid			–	449,175
Change in non-cash working capital			(87,383)	(186,990)
Cash flow			$    963,046	$    871,144

Capital Expenditures

Management uses the term "capital expenditures" as a measure of capital investment in exploration and production activity, as well as property acquisitions and dispositions, and such spending is compared to the Company's annual budgeted capital expenditures. The most directly comparable GAAP measure for capital expenditures is cash flow used in investing activities. A summary of the reconciliation of cash flow used in investing activities to capital expenditures, is set forth below:

			Three Months Ended March 31,
(000s)			2025	2024
Cash flow used in investing activities (per GAAP)			$    714,079	$    584,229
Change in non-cash working capital			110,939	(27,984)
Capital expenditures			$    825,018	$    556,245

EP Spending

Management uses the term "EP spending" or exploration and production expenditures as a measure of capital investment in exploration and production activity, and such spending is compared to the Company's annual budgeted exploration and production expenditures. The most directly comparable GAAP measure for EP spending is cash flow used in investing activities. A summary of the reconciliation of cash flow used in investing activities to EP spending is set forth below:

			Three Months Ended March 31,
(000s)			2025	2024
Cash flow used in investing activities (per GAAP)			$      714,079	$    584,229
Change in non-cash working capital			110,939	(27,984)
Property acquisitions			(12,143)	(412)
Proceeds from divestitures			1,023	5,497
Other			(16,166)	(12,631)
EP Spending			$    797,732	$    548,699

Free Cash Flow

Management uses the term "free cash flow" for its own performance measure and to provide shareholders and potential investors with a measurement of the Company's efficiency and its ability to generate the cash necessary to fund its future growth expenditures, to repay debt and provide shareholder returns.  Free cash flow is defined as cash flow less capital expenditures, excluding acquisitions and dispositions.  Free cash flow is prior to dividend payment. The most directly comparable GAAP measure for cash flow is cash flow from operating activities. See "Non-GAAP Financial Measures – Cash Flow" and " Non-GAAP Financial Measures – Capital Expenditures" above.

			Three Months Ended March 31,
(000s)			2025	2024
Cash flow			$    963,046	$    871,144
Capital expenditures			(825,018)	(556,245)
Property acquisitions			12,143	412
Proceeds from divestitures			(1,023)	(5,497)
Free Cash Flow			$    149,148	$    309,814

Operating Netback

Management uses the term "operating netback" as a key performance indicator and one that is commonly presented by other oil and natural gas producers.  Operating netback is defined as the sum of commodity sales from production, premium on risk management activities and realized (loss) on financial instruments less the sum of royalties, transportation costs and operating expenses.  A summary of the reconciliation of operating netback from commodity sales from production, which is a GAAP measure, is set forth below:

			Three Months Ended March 31,
(000s)			2025	2024
Commodity sales from production			$ 1,457,567	$ 1,474,379
Premium on risk management activities			337,609	67,345
Realized gain on financial instruments			96,417	84,445
Royalties			(179,159)	(150,471)
Transportation costs			(317,197)	(282,053)
Operating expenses			(295,661)	(259,233)
Operating netback			$ 1,099,576	$    934,412

Non-GAAP Financial Ratios

Operating Netback per-boe

Management calculates "operating netback per-boe" as operating netback divided by total production for the period.  Operating netback per-boe is a key performance indicator and measure of operational efficiency and one that is commonly presented by other oil and natural gas producers.  A summary of the calculation of operating netback per boe, is set forth below:

			Three Months Ended March 31,
($/boe)			2025	2024
Revenue, excluding processing income			$       32.95	$       30.18
Royalties			(3.12)	(2.79)
Transportation costs			(5.53)	(5.23)
Operating expenses			(5.15)	(4.81)
Operating netback			$       19.15	$       17.35

Capital Management Measures

Adjusted Working Capital

Management uses the term "adjusted working capital" for its own performance measures and to provide shareholders and potential investors with a measurement of the Company's liquidity. A summary of the reconciliation of working capital (deficit) to adjusted working capital (deficit), is set forth below:

(000s)	As at March 31, 2025	As at December 31, 2024
Working capital (deficit)	$ (566,965)	$   (167,623)
Fair value of financial instruments – short-term (asset)	(148,833)	(315,365)
Lease liabilities – short-term	7,888	8,385
Decommissioning obligations – short-term	60,000	60,000
Unrealized foreign exchange in working capital – liability (asset)	(2,897)	(15,354)
Adjusted working capital (deficit)	$ (650,807)	$   (429,957)

Net Debt

Management uses the term "net debt", as a key measure for evaluating its capital structure and to provide shareholders and potential investors with a measurement of the Company's total indebtedness.  A summary of the composition of net debt, is set forth below:

(000s)	As at March 31, 2025	As at December 31, 2024
Bank debt	$   (493,066)	$ (574,339)
Senior unsecured notes	(698,566)	(698,436)
Adjusted working capital (deficit)	(650,807)	(429,957)
Net debt	$ (1,842,439)	$ (1,702,732)

Supplementary Financial Measures

The following measures are supplementary financial measures: cash flow per diluted share, operating expenses ($/boe), cash general and administrative expenses ($/boe) and transportation costs ($/boe). These measures are calculated by dividing the numerator by a diluted share count or by total production for the period, depending on the financial measure discussed.

ESTIMATED DRILLING INVENTORY

This news release discloses drilling locations in respect of the two acquisitions. Drilling locations are categorized as follows: (i) proved undeveloped locations; (ii) probable undeveloped locations; (iii) unbooked locations; and (iv) an aggregate total of (i), (ii) and (iii). Of the 464 (net) locations disclosed in this press release, 119.1 are proved undeveloped locations, 0.0 (net) are proved non-producing locations, 83.7 (net) are probable undeveloped locations, and 261.8 (net) are unbooked. Proved producing wells, proved undeveloped locations, proved non-producing locations, probable undeveloped locations and probable non-producing locations are based on internal estimates and account for drilling locations that have associated proved and/or probable reserves, as applicable, and expected to be booked in the Company's 2025 reserve report. Unbooked locations are internal estimates based on the Company's prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources (including contingent and prospective). Unbooked locations have been identified by management as an estimation of the Company's multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which the Company will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of funding, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While a certain number of the unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.

OIL AND GAS METRICS

This news release contains certain oil and gas metrics which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included in this document to provide readers with additional measures to evaluate the Company's performance; however, such measures are not reliable indicators of the Company's future performance and future performance may not compare to the Company's performance in previous periods and therefore such metrics should not be unduly relied upon.

SUPPLEMENTAL INFORMATION REGARDING PRODUCT TYPES

This news release includes references to Q1 2025 average daily production, Q2 2025 forecast average daily production and 2025 forecast average daily production. The following table is intended to provide supplemental information about the product type composition for each of the production figures that are provided in this news release:

		Light and Medium Crude Oil^(1)		Conventional Natural Gas		Shale Natural Gas		Natural Gas Liquids^(1)		Oil Equivalent Total
		Company Gross (bbls)		Company Gross (mcf)		Company Gross (mcf)		Company Gross (bbls)		Company Gross (boe)
Q1 2025 Average Daily Production		52,565		1,608,342		1,334,232		94,873		637,867
Q2 2025 Forecast Average Daily Production		56,000		1,475,500		1,320,500		98,000		620,000
2025 Forecast Average Daily Production		58,100		1,582,500		1,347,500		103,550		650,000

(1)	For the purposes of this disclosure, condensate has been combined with Light and Medium Crude Oil as the associated revenues and certain costs of condensate are similar to Light and Medium Crude Oil.   Accordingly, NGLs in this disclosure exclude condensate.

CREDIT RATINGS

Credit ratings are intended to provide investors with an independent measure of credit quality of an issue of securities. Credit ratings are not recommendations to purchase, hold or sell securities and do not address the market price or suitability of a specific security for a particular investor. There is no assurance that any rating will remain in effect for any given period of time or that any rating will not be revised or withdrawn entirely by a rating agency in the future if, in its judgment, circumstances so warrant.

INITIAL PRODUCTION RATES

Any references in this news release to initial production rates are useful in confirming the presence of hydrocarbons; however, such rates are not determinative of the rates at which such wells will continue production and decline thereafter and are not necessarily indicative of long-term performance or ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the company. Such rates are based on field estimates and may be based on limited data available at this time.

GENERAL

See also "Forward-Looking Statements", and "Non-GAAP and Other Financial Measures" in the most recently filed Management's Discussion and Analysis. 

CERTAIN DEFINITIONS:

1H	first half
2H	second half
bbl	barrel
bbls/day	barrels per day
bbl/mmcf	barrels per million cubic feet
bcf	billion cubic feet
bcfe	billion cubic feet equivalent
bpd or bbl/d	barrels per day
boe	barrel of oil equivalent
boepd or boe/d	barrel of oil equivalent per day
bopd or bbl/d	barrel of oil, condensate or liquids per day
DUC	drilled but uncompleted wells
Dutch TTF	Dutch Title Transfer Facility, a natural gas pricing location within the Netherlands
EP	exploration and production
FERC	Federal Energy Regulatory Commission
gj	gigajoule
gjs/d	gigajoules per day
JKM	Japan Korea Marker
mbbls	thousand barrels
mmbbls	million barrels
mboe	thousand barrels of oil equivalent
mboepd	thousand barrels of oil equivalent per day
mcf	thousand cubic feet
mcfpd or mcf/d	thousand cubic feet per day
mcfe	thousand cubic feet equivalent
mmboe	million barrels of oil equivalent
mmbtu	million British thermal units
mmbtu/d	million British thermal units per day
mmcf	million cubic feet
mmcfpd or mmcf/d	million cubic feet per day
MPa	megapascal
mstb	thousand stock tank barrels
natural gas	conventional natural gas and shale gas
NGL or NGLs	natural gas liquids
PGE	Pacific Gas & Electric
Tcf	trillion cubic feet

MANAGEMENT'S DISCUSSION AND ANALYSIS AND CONSOLIDATED FINANCIAL STATEMENTS

To view Tourmaline's Management's Discussion and Analysis and Consolidated Financial Statements for the periods ended March 31, 2025 and 2024, please refer to SEDAR+ (www.sedarplus.ca) or Tourmaline's website at www.tourmaline.com.

ABOUT TOURMALINE OIL CORP.

Tourmaline is Canada's largest and most active natural gas producer dedicated to producing the lowest-development-cost natural gas in North America.  We are an investment grade exploration and production company providing strong and predictable operating and financial performance through the development of our three core areas in the Western Canadian Sedimentary Basin.  With our existing large reserve base, decades-long drilling inventory, relentless focus on execution, cost management, safety and environmental performance improvement, we are excited to provide shareholders an excellent return on capital and an attractive source of income through our base dividend and surplus free cash flow distribution strategies.

SOURCE Tourmaline Oil Corp.

For further information, please contact: Tourmaline Oil Corp.: Michael Rose, Chairman, President and Chief Executive Officer, [phone] OR Tourmaline Oil Corp.: Brian Robinson, Chief Financial Officer, [phone], [email protected] OR Tourmaline Oil Corp.: Scott Kirker, Chief Legal Officer and External Affairs, [phone], [email protected] OR Tourmaline Oil Corp.: Jamie Heard, Vice President, Capital Markets, [phone], [email protected] OR Tourmaline Oil Corp.: Suite 2900, 250 - 6th Avenue S.W., Calgary, Alberta T2P 3H7, Phone: [phone], Facsimile: [phone], E-mail: [email protected]; Website: www.tourmaline.com