SURGE ENERGY INC. ANNOUNCES FIRST QUARTER FINANCIAL AND OPERATING RESULTS

CALGARY, AB, May 7, 2025 /CNW/ - Surge Energy Inc. ("Surge" or the "Company") (TSX: SGY) is pleased to announce financial and operating results for the quarter ended March 31, 2025, as well as an update on Surge's latest operational achievements.

Select financial and operating information is outlined below and should be read in conjunction with the Company's unaudited condensed interim financial statements and management's discussion and analysis for the three months ended March 31, 2025, available at www.sedarplus.ca and on Surge's website at www.surgeenergy.ca.

Sparky Core Area Production (CNW Group/Surge Energy Inc.)

SURGE ENERGY INC. ANNOUNCES FIRST QUARTER FINANCIAL AND OPERATING RESULTS (CNW Group/Surge Energy Inc.)

MESSAGE TO SHAREHOLDERS

Based on continued strong drilling results in the Company's two core areas, in Q1/25 Surge delivered one of the largest quarterly outperformances in the Company's corporate history, as compared to Analyst consensus estimates, for both production and adjusted funds flow ("AFF")¹ for the quarter.

Surge is a publicly traded intermediate oil company with a highly focused, conventional, light and medium gravity crude oil asset and opportunity base, with an internally estimated drilling inventory that supports more than 12 years of development drilling². The focus of Surge's Board of Directors and Management is to maximize free cash flow available for shareholder returns, through a combination of:

1. A sustainable base dividend;
2. Strategic share buybacks;
3. Debt reduction;
4. Organic production per share growth; and
5. Accretive acquisitions.

In Q1/25 Surge's production averaged 23,567 boepd (89 percent liquids), well above the Company's budgeted average 2025 production level estimate of 22,500 boepd. This consistent quarterly production outperformance is primarily due to better than anticipated drilling results in Surge's two core areas. Notably, Surge continues to achieve excellent drilling results² at the Company's recent Sparky crude oil discovery at Hope Valley.

Surge's continued operational focus on its conventional, low cost Sparky and SE Saskatchewan core areas, in conjunction with the strategic dispositions of non-core assets in 2024, has resulted in a significant increase to the Company's AFF per boe over the past year. On this basis, while received oil prices increased by only 5 percent between Q1/24 and Q1/25, Surge's AFF per boe¹ increased by 37 percent to $37.76 per boe in Q1/25, from $27.57 per boe in Q1/24.

The recent volatility in global markets has had a meaningful impact on current crude oil prices as WTI prices have decreased from approximately US$71.50/bbl on March 31, 2025 to a current spot price of approximately US$59/bbl. In light of this instability, Surge's proactive hedging program is working as designed, to reduce the impact of crude oil pricing volatility on the Company's cash flow and free cash flow.

In this regard, Surge has hedged 9,500 bbl/d of its forecasted Q2/25 and Q3/25 oil production with an average floor price of approximately US$71 WTI per barrel, representing approximately 55 percent of the Company's forecasted net after royalty oil production over this period.

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	^1 This is a non-GAAP and other financial measure which is defined under Non-GAAP and Other Financial Measures.
	^2 See Drilling Inventory.

Surge's strategic 2025 and 2026 WTI crude oil hedges have a current value of approximately $30 million³, based on current forward strip WTI pricing.

Q1 2025 FINANCIAL AND OPERATIONAL HIGHLIGHTS

In Q1/25 Surge's production averaged 23,567 boepd (89 percent liquids), well above the Company's budgeted average 2025 production estimate of 22,500 boepd. 

During Q1/25 WTI crude oil prices averaged US$71.72 per barrel, as compared to US$70.27 per barrel in Q4/24. While Q1/25 WTI pricing was similar to the prior quarter, Surge's AFF increased by 5 percent to $80.1 million, as compared to $76.1 million in Q4/24. Cash flow from operating activities generated in Q1/25, inclusive of changes in non-cash working capital, increased by 29 percent to $83.5 million, as compared to $64.8 million in Q4/24.

The increase in AFF in Q1/25 as compared to Q4/24 is due in large part to Surge's continued operational focus and drilling success in its two core areas. This has resulted in a 10 percent improvement to the Company's operating netback per boe¹, which increased from $39.03 per boe in Q4/24 to $43.08 per boe in Q1/25.

During Q1/25 Surge distributed $13.0 million in dividends to shareholders, representing only 16 percent of AFF generated during the period. Surge returned an additional $5.0 million to shareholders in Q1/25 through its ongoing share buyback program, repurchasing 858,800 shares under the Company's normal course issuer bid ("NCIB"). In total, Surge returned $18.0 million directly to shareholders during the first quarter of 2025, which represents approximately 23 percent of Q1/25 AFF.

Highlights from the Company's Q1 2025 financial and operating results include:

• Higher than budgeted average daily production of 23,567 boepd (89 percent liquids);
• Generating $80.1 million of AFF in Q1/25, as compared to $76.1 million in Q4/24;
• Delivering $83.5 million of cash flow from operating activities in Q1/25, as compared to $64.8 million in Q4/24;
• Increasing operating netbacks by 10 percent to $43.08 per boe in Q1/25, from $39.03 per boe in Q4/24;
• Drilling 24 gross (21.0 net) wells, with activity entirely focused in the Company's Sparky and SE Saskatchewan conventional core areas;
• Distributing $13.0 million to Surge's shareholders by way of the Company's $0.52 per share per annum base dividend (paid monthly);
• Returning an additional $5.0 million to shareholders by way of the Company's NCIB share repurchase program;
• Decreasing net debt¹ by $49.9 million (17 percent), from $295.9 million in Q1/24, to $246.0 million in Q1/25; and
• On an annualized basis, Q1/25 AFF represented 0.77 times Q1/25 net debt of $246.0 million.

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	^3 Represents the forecasted settlement value of the Company's Q2/25 through Q1/26 WTI hedge positions, using WTI and CAD/USD forward pricing as of May 7, 2025.

FINANCIAL AND OPERATING HIGHLIGHTS

FINANCIAL AND OPERATING HIGHLIGHTS	Three Months Ended March 31,
($000s except per share and per boe)	2025	2024	% Change
Financial highlights
Oil sales	157,206	150,716	4 %
NGL sales	1,129	3,935	(71) %
Natural gas sales	2,387	3,516	(32) %
Total oil, natural gas, and NGL revenue	160,722	158,167	2 %
Cash flow from operating activities	83,470	66,785	25 %
Per share - basic ($)	0.83	0.66	26 %
Per share diluted ($)	0.82	0.65	26 %
Adjusted funds flow^a	80,107	62,487	28 %
Per share - basic ($)^a	0.80	0.62	29 %
Per share diluted ($)	0.79	0.61	30 %
Net income (loss)	8,246	(3,630)	nm^b
Per share basic ($)	0.08	(0.04)	nm
Per share diluted ($)^c	0.08	(0.04)	nm
Expenditures on property, plant and equipment	54,399	49,400	10 %
Net acquisitions and dispositions	44	(8)	nm
Net capital expenditures	54,443	49,392	10 %
Net debt^a, end of period	246,003	295,924	(17) %
Operating highlights
Production:
Oil (bbls per day)	20,673	20,620	— %
NGLs (bbls per day)	248	860	(71) %
Natural gas (mcf per day)	15,877	20,539	(23) %
Total (boe per day) (6:1)	23,567	24,903	(5) %
Average realized price (excluding hedges):
Oil ($ per bbl)	84.49	80.32	5 %
NGL ($ per bbl)	50.53	50.25	1 %
Natural gas ($ per mcf)	1.67	1.88	(11) %
Netback ($ per boe)
Petroleum and natural gas revenue	75.77	69.79	9 %
Realized gain on commodity and FX contracts	0.67	0.06	nm
Royalties	(13.42)	(13.30)	1 %
Net operating expenses^a	(18.78)	(21.81)	(14) %
Transportation expenses	(1.16)	(1.18)	(2) %
Operating netback^a	43.08	33.56	28 %
G&A expense	(2.64)	(2.26)	17 %
Interest expense	(2.68)	(3.73)	(28) %
Adjusted funds flow^a	37.76	27.57	37 %
Common shares outstanding, end of period	99,523	100,581	(1) %
Weighted average basic shares outstanding	99,979	100,529	(1) %
Stock-based compensation dilution^c	1,263	1,646	(23) %
Weighted average diluted shares outstanding	101,242	102,175	(1) %
^aThis is a non-GAAP and other financial measure which is defined under Non-GAAP and Other Financial Measures.
^bThe Company views this change calculation as not meaningful, or "nm".
^c Dilution is not reflected in the calculation of net loss for the three months ended March 31, 2024.

OPERATIONS UPDATE: CONTINUED DRILLING SUCCESS IN SPARKY AND SE SASKATCHEWAN CORE AREAS DRIVES PRODUCTION OUTPERFORMANCE

Surge's Q1/25 production averaged 23,567 boepd (89 percent liquids), more than 1,000 boepd ahead of the Company's budgeted average 2025 production estimate of 22,500 boepd. This continued quarterly production outperformance is due to better than anticipated drilling results in Surge's two core areas, highlighted by excellent ongoing drilling results² at the Company's recent Sparky discovery at Hope Valley. 

Surge's Q1/25 drilling program was initiated with two rigs drilling in the Sparky core area and one rig drilling in the SE Saskatchewan core area. The Company's Q1/25 drilling program consisted of a total of 24 gross (21.0 net) wells, with 13 gross (13.0 net) wells drilled in the Sparky core area and 11 gross (8.0 net) drilled in the SE Saskatchewan core area.

The development and delineation of Surge's Hope Valley Sparky discovery continued in Q1/25 with the drilling of four additional multi-lateral horizontal wells. These wells were drilled with 12 lateral legs each, accessing an average of 14,500 meters of shallow, conventional Sparky sandstone reservoir per well, utilizing the application of modern multi-lateral open hole drilling technology. 

Since the beginning of 2024 Surge has drilled eight multi-lateral wells at Hope Valley that have more than three months of production data. These eight wells produced at an average IP90 of 220 bopd, which exceeded Management's IP90 type curve expectations of 168 bopd by more than 30 percent².

Production at Surge's core Hope Valley Sparky asset has grown to over 3,500 boepd during the past 15 months. Furthermore, Surge now estimates that the Company has more than 80 net drilling locations2 remaining at Hope Valley.

Surge's Sparky core area production has now grown to more than 13,000 boepd currently, as set forth below (88 percent medium gravity oil; with an average of 23°API):

In addition, the Company has more than 490 net drilling locations in its Sparky core area providing an approximate 14 year inventory ie. at the current drilling pace of 34 Sparky locations per year².

OUTLOOK: FOCUSED, PREMIUM ASSET QUALITY DRIVES SUPERIOR RETURNS

Based on continued strong drilling results in the Company's two core areas, in Q1/25 Surge delivered one of the largest quarterly outperformances in the Company's corporate history, as compared to Analyst consensus estimates, for both production and AFF for the quarter.

In Q1/25 production averaged 23,567 boepd (89 percent liquids), cash flow from operating activities increased by 25 percent as compared to Q1/24, and AFF per boe increased 37 percent over the same period. Additionally, the Company's net debt decreased 17 percent, from $295.9 million in Q1/24, to $246.0 million in Q1/25.

Surge's premium crude oil asset base is now more than 90 percent focused in two of the top four crude oil plays in Canada[4] based on per well payout economics in its Sparky (~13,000 boepd; 88 percent medium gravity oil and liquids) and SE Saskatchewan (~8,000 boepd; 90 percent light oil and liquids) core areas.

Surge is well positioned to continue delivering attractive shareholder returns in 2025 and beyond, based on the key corporate fundamentals set forth below:

• Average 2025 production of 22,500 boepd (89 percent liquids);
• Estimated 2025 AFF of $275 million⁵;
• Estimated 2025 cash flow from operating activities of $255 million⁵;
• A $52 million annual base cash dividend ($0.52 per share annual dividend, paid monthly), which represents 19 percent of the Company's forecasted 2025 AFF of $275 million;
• An estimated 25 percent annual corporate decline⁶;
• A $250 million undrawn first lien credit facility;
• Approximately 900 (net) internally estimated drilling locations, providing a 12 year drilling inventory²; and
• $1.3 billion in tax pools (representing an estimated 4 year tax horizon)⁵.

Management is closely monitoring the recent drop in world crude oil prices. Given Surge's continued quarterly production outperformance, supported by the Company's 2025 crude oil hedging program, Surge has the flexibility to decrease its 2025 capital expenditure budget and still achieve the Company's year-end production exit rate guidance of 22,500 boepd.

As at March 31, 2025, Surge had no drawn balance on the Company's first $250 million lien credit facilities. Furthermore, Surge's convertible debentures do not mature until December of 2028, and the Company's senior unsecured notes mature in September of 2029.

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	^4 Peters & Co. (January 8, 2025 North American Crude Oil and Natural Gas Plays). Pricing assumptions: US$69 WTI, US$13 WCS differential, US$3.60 NYMEX, and C$2.75 AECO.
	^5 Pricing Assumptions: US$70 WTI, US$13.50 WCS differential, US$3.50 EDM differential, $0.725 CAD/USD FX and $2.50 AECO.
	^6 See Oil and Gas Advisories.

FORWARD LOOKING STATEMENTS

This press release contains forward-looking statements. The use of any of the words "anticipate", "continue", "could",  "estimate", "expect", "may", "will", "project", "should", "believe", "potential" and similar expressions are intended to identify forward-looking statements. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements.

More particularly, this press release contains statements concerning: Surge's estimated drilling inventory that supports more than 12 years of development drilling; Surge's declared focus and primary goals, and the actions to achieve such goas including, but not limited through a sustainable base dividend, strategic share buybacks and debt reduction;  crude oil fixed price hedges protecting the Company's 2025 free cash flow profile and expectations with respect to Surge's hedging program; Surge's estimates with respect to its drilling locations and estimates with respect to the amount of inventory; the repeatability and consistency of drilling results at Hope Valley and moving this asset the full development phase; estimated Sparky drilling locations remaining on the Company's Hope Valley land and the future development of such land; Surge's planned 2025 drilling program and focus, including expectations regarding the number of wells to be drilled and the types thereof; Surge's 2025 capital program and focus; Surge's intention to have a dedicated rig drilling multi-lateral wells in Hope Valley for the entire year; management's belief that Surge is well positioned to deliver attractive shareholder returns; share repurchases under the Company's NCIB; Surge's key corporate fundamentals; the ability of Surge to reduce its capital expenditure budget and still achieve the Company's year end production exit rate guidance; management's 2025 budgeted average production guidance; Surge's reserves, future net revenue, future development capital and reserve life index; Surge continuing to execute an active drilling program at both the Sparky and SE Saskatchewan core areas during the first half of 2025 and the number of wells to be drilled thereat; and management's expectations regarding Surge's 2025 average production, AFF, cash flow from operating activities, dividends, drilling inventory and locations, annual corporate decline rates, tax pools and tax horizon.

The forward-looking statements are based on certain key expectations and assumptions made by Surge, including expectations and assumptions the performance of existing wells and success obtained in drilling new wells; anticipated expenses, cash flow and capital expenditures; the application of regulatory and royalty regimes; that Surge's strategies will maximize free cash flow available for shareholder returns; that Surge's hedging programs will reduce the impact of crude oil pricing volatility on the Company's cash flow and free cash flow; prevailing commodity prices and economic conditions; development and completion activities; the performance of new wells; the successful implementation of waterflood programs; the availability of and performance of facilities and pipelines; the geological characteristics of Surge's properties; the successful application of drilling, completion and seismic technology; the determination of decommissioning liabilities; prevailing weather conditions; exchange rates; licensing requirements; the impact of completed facilities on operating costs; the availability and costs of capital, labour and services; and the creditworthiness of industry partners.

Although Surge believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because Surge can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve 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, risks associated with the condition of the global economy, including trade, public health and other geopolitical risks; risks associated with the oil and gas industry in general (e.g. operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks); commodity price and exchange rate fluctuations and constraint in the availability of services, adverse weather or break-up conditions; the imposition or expansion of tariffs imposed by domestic and foreign governments or the imposition of other restrictive trade measures, retaliatory or countermeasures implemented by such governments, including the introduction of regulatory barriers to trade and the potential effect on the demand and/or market price for Surge's products and/or otherwise adversely affects Surge; uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures; and failure to obtain the continued support of the lenders under Surge's bank line. Certain of these risks are set out in more detail in Surge's AIF dated March 5, 2025 and in Surge's MD&A for the year ended December 31, 2024, both of which have been filed on SEDAR+ and can be accessed at www.sedarplus.ca.

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

Oil and Gas Advisories

Barrel of Oil Equivalency

The term "boe" means barrel of oil equivalent on the basis of 1 boe to 6,000 cubic feet of natural gas. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 1 boe for 6,000 cubic feet of natural gas is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. "Boe/d" and "boepd" mean barrel of oil equivalent per day. Bbl means barrel of oil and "bopd" means barrels of oil per day.  NGLs means natural gas liquids.

Oil and Gas Metrics

This press release contains certain oil and gas metrics and defined terms which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar metrics/terms presented by other issuers and may differ by definition and application. All oil and gas metrics/terms used in this document are defined below:

"Capital payout" or "payout per well", is the time period for the operating netback of a well to equate to the individual cost of drilling, completing and equipping the well. Management uses capital payout and payout per well as a measure of capital efficiency of a well to make capital allocation decisions.

"Decline" is the amount existing production decreases year over year, without new drilling. Sproule's 2024 year end reserves have a Proved Developed Producing ("PDP") decline of 27 percent and a Proven Plus Probable Developed Producing ("P+PDP") decline of 25 percent.

Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare our operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this press release, should not be relied upon for investment or other purposes.

Drilling Inventory

This press release discloses drilling locations in two categories: (i) booked locations; and (ii) unbooked locations. Booked locations are proved locations and probable locations derived from an external evaluation using standard practices as prescribed in the Canadian Oil and Gas Evaluations Handbook and account for drilling locations that have associated proved and/or probable reserves, as applicable. 

Unbooked locations are internal estimates based on prospective acreage and assumptions as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Unbooked locations have been identified by Surge's internal certified Engineers and Geologists (who are also Qualified Reserve Evaluators ("QRE")) as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that 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 actually drills wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been de-risked by drilling existing wells in relative close proximity to such unbooked drilling locations, 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.

Assuming a January 1, 2025 reference date, the Company will have over >975 gross (>900 net) drilling locations identified herein; of these >575 gross (>525 net) are unbooked locations. Of the 367 net booked locations identified herein, 284 net are Proved locations and 83 net are Probable locations based on Sproule's 2024 year end reserves. Assuming an average number of net wells drilled per year of 75, Surge's >900 net locations provide 12 years of drilling.

Assuming a January 1, 2025 reference date, the Company will have over >500 gross (>475 net) Sparky Core area drilling locations identified herein; of these >300 gross (>300 net) are unbooked locations. Of the 196 net booked locations identified herein, 143 net are Proved locations and 53 net are Probable locations based on Sproule's 2024 year end reserves. Assuming an average number of wells drilled per year of 40, Surge's >475 net locations provide >12 years of drilling.

Assuming a January 1, 2025 reference date, the Company will have over >80 gross (>80 net) Sparky Hope Valley area drilling locations identified herein; of these >60 gross (>60 net) are unbooked locations. Of the 22 net booked locations identified herein, 17 net are Proved locations and 5 net are Probable locations based on Sproule's 2024 year end  reserves.

Surge's internally used type curves were constructed using a representative, factual and balanced analog data set, as of January 1, 2024. All locations were risked appropriately, and Estimated Ultimate Recovery ("EUR") was measured against Discovered Petroleum Initially In Place ("DPIIP") estimates to ensure a reasonable recovery factor was being achieved based on the respective spacing assumption. Other assumptions, such as capital, operating expenses, wellhead offsets, land encumbrances, working interests and NGL yields were all reviewed, updated and accounted for on a well-by-well basis by Surge's QRE's. All type curves fully comply with Part 5.8 of the Companion Policy 51 – 101CP.

Surge's internal Hope Valley type curve profile of 172 bopd (IP30), 168 bopd (IP90) and 175 mbbl (175 mboe) EUR reserves per well, with assumed $2.5 MM per well capital, has a payout of ~10 months @ US$70/bbl WTI (C$93.05/bbl LSB) and a ~175 percent IRR.

Since the beginning of 2024, Surge has drilled eight multi-lateral wells at Hope Valley that have more than three months of production data. These eight wells produced at an average IP90 of 220 bopd, which exceeded Management's IP90 type curve expectations of 168 bopd by over 30 percent.

Non-GAAP and Other Financial Measures

This press release includes references to non-GAAP and other financial measures used by the Company to evaluate its financial performance, financial position or cash flow. These specified financial measures include non-GAAP financial measures and non-GAAP ratios and are not defined by IFRS Accounting Standards ("IFRS") as issued by the International Accounting Standards Board, and therefore are referred to as non-GAAP and other financial measures. These non-GAAP and other financial measures are included because Management uses the information to analyze business performance, cash flow generated from the business, leverage and liquidity, resulting from the Company's principal business activities and it may be useful to investors on the same basis. None of these measures are used to enhance the Company's reported financial performance or position. The non-GAAP and other financial measures do not have a standardized meaning prescribed by IFRS and therefore are unlikely to be comparable to similar measures presented by other issuers. They are common in the reports of other companies but may differ by definition and application. All non-GAAP and other financial measures used in this document are defined below, and as applicable, reconciliations to the most directly comparable GAAP measure for the period ended March 31, 2025, have been provided to demonstrate the calculation of these measures:

Adjusted Funds Flow & Adjusted Funds Flow Per Share

Adjusted funds flow is a non-GAAP financial measure. The Company adjusts cash flow from operating activities in calculating adjusted funds flow for changes in non-cash working capital, decommissioning expenditures, and cash settled transaction and other costs. Management believes the timing of collection, payment or incurrence of these items involves a high degree of discretion and as such, may not be useful for evaluating Surge's cash flows.

Changes in non-cash working capital are a result of the timing of cash flows related to accounts receivable and accounts payable, which Management believes reduces comparability between periods. Management views decommissioning expenditures predominately as a discretionary allocation of capital, with flexibility to determine the size and timing of decommissioning programs to achieve greater capital efficiencies and as such, costs may vary between periods. Transaction and other costs represent expenditures associated with property acquisitions and dispositions, debt restructuring and employee severance costs, which Management believes do not reflect the ongoing cash flows of the business, and as such, reduces comparability. Each of these expenditures, due to their nature, are not considered principal business activities and vary between periods, which Management believes reduces comparability.

Adjusted funds flow per share is a non-GAAP ratio, calculated using the same weighted average basic and diluted shares used in calculating income (loss) per share.

The following table reconciles cash flow from operating activities to adjusted funds flow and adjusted funds flow per share:

	Three Months Ended March 31,
($000s except per share)	2025	2024
Cash flow from operating activities	83,470	66,785
Change in non-cash working capital	(7,718)	(8,953)
Decommissioning expenditures	4,525	3,928
Cash settled transaction and other costs	(170)	727
Adjusted funds flow	80,107	62,487
Per share - basic ($)	0.80	0.62
Per share - diluted ($)	0.79	0.61

Free Cash Flow

Free cash flow is a non-GAAP financial measure. Free cash flow is calculated as cash flow from operating activities, adjusted for changes in non-cash working capital, decommissioning expenditures, and cash settled transaction and other costs, less expenditures on property, plant and equipment. Management uses free cash flow to determine the amount of funds available to the Company for future capital allocation decisions.

Net Debt

Net debt is a non-GAAP financial measure, calculated as bank debt, senior unsecured notes, term debt, plus the liability component of the convertible debentures plus current assets, less current liabilities, however, excluding the fair value of financial contracts, decommissioning obligations, and lease and other obligations. There is no comparable measure in accordance with IFRS for net debt. This metric is used by Management to analyze the level of debt in the Company including the impact of working capital, which varies with the timing of settlement of these balances.

($000s)	As at Mar 31, 2025	As at Dec 31, 2024	As at Mar 31, 2024
Cash	11,736	7,594	—
Accounts receivable	55,506	58,327	62,676
Prepaid expenses and deposits	2,363	3,233	5,525
Accounts payable and accrued liabilities	(94,749)	(95,433)	(98,715)
Dividends payable	(4,313)	(4,350)	(4,023)
Bank debt	—	—	(52,501)
Senior unsecured notes	(171,090)	(170,872)	—
Term debt	(5,637)	(6,224)	(170,675)
Convertible debentures	(39,819)	(39,401)	(38,211)
Net Debt	(246,003)	(247,126)	(295,924)

Net Operating Expenses & Net Operating Expenses per boe

Net operating expenses is a non-GAAP financial measure, determined by deducting processing income, primarily generated by processing third party volumes at processing facilities where the Company has an ownership interest. It is common in the industry to earn third party processing revenue on facilities where the entity has a working interest in the infrastructure asset. Under IFRS, this source of funds is required to be reported as revenue. However, the Company's principal business is not that of a midstream entity whose activities are dedicated to earning processing and other infrastructure payments. Where the Company has excess capacity at one of its facilities, it will look to process third party volumes as a means to reduce the cost of operating/owning the facility. As such, third party processing revenue is netted against operating costs when analyzed by Management.

Net operating expenses per boe is a non-GAAP ratio, calculated as net operating expenses divided by total barrels of oil equivalent produced during a specific period of time.

	Three Months Ended March 31,
($000s)	2025	2024
Operating expenses	41,996	51,937
Less: processing income	(2,162)	(2,504)
Net operating expenses	39,834	49,433
$ per boe	18.78	21.81

Operating Netback, Operating Netback per boe & Adjusted Funds Flow per boe

Operating netback is a non-GAAP financial measure, calculated as petroleum and natural gas revenue and processing and other income, less royalties, realized gain (loss) on commodity and FX contracts, operating expenses, and transportation expenses. Operating netback per boe is a non-GAAP ratio, calculated as operating netback divided by total barrels of oil equivalent produced during a specific period of time. There is no comparable measure in accordance with IFRS. This metric is used by Management to evaluate the Company's ability to generate cash margin on a unit of production basis.

Adjusted funds flow per boe is a non-GAAP ratio, calculated as adjusted funds flow divided by total barrels of oil equivalent produced during a specific period of time.

Operating netback & adjusted funds flow are calculated on a per unit basis as follows:

	Three Months Ended March 31,
($000s)	2025	2024
Petroleum and natural gas revenue	160,722	158,167
Processing and other income	2,162	2,504
Royalties	(28,457)	(30,144)
Realized gain on commodity and FX contracts	1,427	137
Operating expenses	(41,996)	(51,937)
Transportation expenses	(2,458)	(2,663)
Operating netback	91,400	76,064
G&A expense	(5,598)	(5,126)
Interest expense	(5,695)	(8,451)
Adjusted funds flow	80,107	62,487
Barrels of oil equivalent (boe)	2,121,090	2,266,221
Operating netback ($ per boe)	43.08	33.56
Adjusted funds flow ($ per boe)	37.76	27.57

For more information about Surge, please visit our website at www.surgeenergy.ca:

Neither the TSX nor its Regulation Services Provider (as that term is defined in the policies of the TSX) accepts responsibility of the accuracy of this release.

SOURCE Surge Energy Inc.

FOR FURTHER INFORMATION, PLEASE CONTACT: Paul Colborne, President & CEO, [phone], [email protected]; Jared Ducs, Chief Financial Officer, [phone], [email protected]