CALGARY, AB , July 28, 2025 /CNW/ - Surge Energy Inc. ("Surge" or the "Company") (TSX: SGY) is pleased to announce financial and operating results for the quarter ended June 30, 2025, as well as an update on the Company's latest operational achievements.

As a result of continued, successful drilling results in Surge's two core areas, the Company is revising its 2025 operating and capital budget guidance. Average 2025 production guidance has now been increased from 22,500 boepd to 23,000 boepd, while budgeted capital expenditures for 2025 are now estimated to be $155 million, $15 million lower than Surge's original capital guidance of $170 million.

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 and six months ended June 30, 2025, available at www.sedarplus.ca and on Surge's website at www.surgeenergy.ca.

Q2/25 MESSAGE TO SHAREHOLDERS

During Q2/25, WTI crude oil prices averaged US$63.88 per barrel, and Surge generated adjusted funds flow ("AFF")¹ of $72.8 million, with cash flow from operating activities of $56.3 million.

Strong drilling results in the Company's Sparky and SE Saskatchewan core areas continue to drive production outperformance, as compared to Surge's 2025 budget guidance press released on December 19, 2024.

In the 1H/25, Surge's average production was 23,579 boepd (89 percent liquids), more than 1,000 boepd ahead of the Company's 22,500 boepd production guidance for 2025. In Q2/25, Surge's production averaged 23,589 boepd (89 percent liquids), also above the Company's budgeted average 2025 production estimate. This consistent production outperformance is primarily due to continued, successful drilling results in Surge's two core operating areas.

At Hope Valley in the Company's Sparky core area, Management is encouraged by the lower decline production profile of the initial wells drilled in the play. Notably, the key discovery well at Hope Valley (09-30-046-4W4) has now been on production for 17 months, with cumulative production of more than 73,000 bbl. This well is currently producing significantly above Surge's internal type curve expectations².

Based on these consistent core area drilling results, Surge is now upwardly revising the Company's 2025 average production guidance from 22,500 boepd to 23,000 boepd. Additionally, with the improved capital efficiencies experienced in its Sparky and SE Saskatchewan core areas, Surge is also reducing its capital expenditure budget guidance for the year. The Company now anticipates spending $155 million on property, plant, and equipment in 2025, a decrease of $15 million from Surge's previous capital guidance of $170 million.  

On this basis, the Company's capital efficiencies are now projected to have improved by more than 20 percent year-over-year, with annual capital expenditures dropping by over $40 million, from $195.1 million in 2024 to an estimated $155 million in 2025. 

In Q2/25, net operating expenses¹ were $17.08 per boe, a decrease of $3.23 per boe (16 percent) as compared to $20.31 per boe in Q2/24. This decrease in operating expenses is due to the Company's continued drilling and operational success in the Sparky and SE Saskatchewan core areas, which now represent over 92 percent of Surge's production. 

The combination of increased 2025 production guidance levels, together with lower than budgeted exploration and development expenditures and net operating expenses, has resulted in an increase to the Company's estimated 2025 free cash flow ("FCF")¹. Surge's 2025 annualized FCF is now forecasted to increase to $105 million from the previously budgeted $85 million³.

Surge's proactive hedging program continues to work as designed, reducing the impact of recent crude oil pricing volatility on the Company's cash flow from operating activities and FCF. In this regard, Surge has hedged 8,750 bbl/d of its Q3/25 oil production with an average floor price of approximately US$71WTI per barrel, representing approximately 50 percent of the Company's forecasted net after royalty production over this period.

Q2/25 FINANCIAL AND OPERATIONAL HIGHLIGHTS

In Q2/25, Surge's production averaged 23,589 boepd (89 percent liquids), above the Company's budgeted average 2025 production estimate of 22,500 boepd.  During the quarter, WTI crude oil prices averaged US$63.88 per barrel, and Surge generated AFF of $72.8 million, with cash flow from operating activities of $56.3 million.

During Q2/25, the Company spent $30.8 million on property, plant, and equipment, resulting in FCF of $41.9 million for the quarter. On this basis, FCF represented 58 percent of the AFF generated in the quarter.

In Q2/25, Surge distributed $12.9 million in dividends to shareholders, representing only 18 percent of AFF generated during the period. In addition, Surge reduced net debt¹ by $16.9 million in Q2/25, decreasing from $246.0 million as at March 31, 2025 to $229.1 million as at June 30, 2025.

Furthermore, Surge returned an additional $2.2 million to shareholders in Q2/25 through its ongoing share buyback program, repurchasing 431,100 shares under the Company's normal course issuer bid ("NCIB").

In total, Surge returned $32.0 million to shareholders during Q2/25 through its monthly base dividend, net debt reduction, and share buybacks. These shareholder returns represent 44 percent of Q2/25 AFF.

Highlights from the Company's Q2/25 financial and operating results include:

• Higher than budgeted average daily production of 23,589 boepd (89 percent liquids);
• Generated $72.8 million of AFF, with WTI crude oil prices averaging US$63.88 per barrel;
• Decreased net operating expenses by 16 percent over the past year, from $20.31 per boe in Q2/24 to $17.08 per boe in Q2/25;
• Drilled 5 gross (5.0 net) wells in the quarter;
• Distributed $12.9 million to Surge's shareholders by way of the Company's $0.52 per share per annum base dividend (paid monthly);
• Decreased net debt by $16.9 million, from $246.0 million in Q1/25, to $229.1 million;
• Returned an additional $2.2 million to shareholders by way of the Company's NCIB;
• On an annualized basis, Q2/25 AFF represented 0.79 times Q2/25 net debt of $229.1 million; and
• The Company's $250 million first lien credit facility remained undrawn as at June 30, 2025, providing Surge with substantial available liquidity.

FINANCIAL AND OPERATING HIGHLIGHTS

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

Surge's Q2/25 production averaged 23,589 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 production outperformance is primarily due to the ongoing, successful drilling results in Surge's two core areas, highlighted by consistent open hole multi-lateral drilling success at the Company's recent Sparky discovery at Hope Valley. 

Surge's Q2/25 drilling program was executed with one rig drilling in the Sparky core area, and consisted of a total of 5 gross (5.0 net) wells drilled in the quarter.

Development and delineation at Surge's Hope Valley discovery continued through Q2/25, with the drilling of 3.0 gross (3.0 net) additional open hole multi-lateral horizontal wells. These three wells were drilled with 12 lateral legs each, accessing an average of 15,936 meters of shallow, conventional Sparky sandstone reservoir per well. Additionally, drilling and production operations for all three wells were completed during spring breakup, utilizing a single surface multi-well pad site.  

Surge has now drilled 12 multi-lateral wells at Hope Valley that have more than three months of production data since development of the area began in early 2024. These 12 wells have produced at an average IP90 rate of 215 bopd, exceeding Management's IP90 rate type curve expectations of 168 bopd by more than 25 percent⁴. Surge has now assembled 36 net sections of land at Hope Valley.

Management is encouraged by the continued outperformance and consistency of the key discovery well drilled at Hope Valley. The 09-30-046-4W4 Sparky well at Hope Valley was drilled using the 12-leg design and has already produced over 73,000 barrels of oil over the past 17 months. The 09-30 well has generated more than $4.6 million of net operating income⁵, paid out in nine months, and has paid out nearly two times in 17 months⁶.

In Surge's SE Saskatchewan core area, the Company completed its 1H/25 drilling program on March 13, 2025 prior to shutting down drilling operations due to seasonal spring breakup conditions and associated road bans. Following Q1/25 drilling operations, Surge has experienced lower than anticipated decline rates and higher than budgeted production in its SE Saskatchewan core area. Based on this production outperformance, the Company was able to defer capital and delay its post breakup drilling program in SE Saskatchewan into Q3/25, with drilling resuming in mid-July. Currently there is one drilling rig operating in SE Saskatchewan, primarily focused on developing the Frobisher formation at Surge's light oil Steelman asset.

To date in 2025, Surge has drilled a total of 26.0 net wells, while adding 78.0 net drilling locations to its inventory in the Company's Sparky and SE Saskatchewan core areas through organic Crown land sales and strategic land acquisitions. This adds to Surge's lower risk development drilling inventory of more than 900 net internally identified locations (as of January 1, 2025), providing an inventory of more than 12 years of drilling⁴.

UPWARDLY REVISED 2025 PRODUCTION GUIDANCE ON LOWER CAPITAL EXPENDITURE ESTIMATES

As a result of continued, successful drilling results, Surge's Board and Management have upwardly revised the Company's 2025 annual production guidance from 22,500 boepd to 23,000 boepd, while also reducing capital expenditure estimates for 2025 by $15 million.

Surge's revised 2025 capital and operating budget guidance is now as follows:

OUTLOOK: FOCUSED, PREMIUM ASSET QUALITY DRIVES SUPERIOR RETURNS

Surge's premium crude oil asset base is now more than 90 percent focused in two of the top four crude oil plays in Canada⁷ based on per well payout economics in its Sparky (+13,500 boepd; 88 percent medium gravity oil and liquids) and SE Saskatchewan (~8,000 boepd; 90 percent light oil and liquids) core areas.

Surge expects to deliver attractive shareholder returns in 2025 and beyond based on the key corporate fundamentals set forth below:

• Increased average 2025 production guidance of 23,000 boepd (90 percent liquids);
• Estimated 2025 AFF of $280 million⁸;
• Estimated 2025 cash flow from operating activities of $260 million⁸;
• A $52 million annual base cash dividend ($0.52 per share annual dividend, paid monthly), which represents less than 19 percent of the Company's forecasted 2025 AFF of $280 million;
• An estimated 25 percent annual corporate decline⁹;
• An undrawn $250 million first lien credit facility;
• Approximately 900 (net) internally estimated drilling locations, providing a 12 year drilling inventory4; and
• $1.2 billion in tax pools (representing an estimated 4 year tax horizon)⁸.

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 declared focus and primary goals; Management's 2025 operating and capital budget guidance, average and annual production guidance, capital expenditure budget guidance and FCF forecast; expectations with respect to the  Company's spend on property, plant and equipment in 2025; projections with respect to the Company's capital efficiencies; crude oil fixed price hedges protecting the Company's 2025 free cash flow profile; share repurchases under the Company's NCIB; 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; the resumption of drilling in SE Saskatchewan to mid-July; estimates with respect to its drilling inventory of more than 12 years; expectations with respect to Surge's shareholder returns in 2025 and beyond and the key corporate fundamentals underlining such expectations; 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 concerning the performance of existing wells and success obtained in drilling new wells; anticipated expenses; cash flow and capital expenditures; compliance with and application of regulatory and royalty regimes; prevailing commodity prices and economic conditions; the Company's expectations regarding well production rates, production decline of existing wells and performance and geographic location of new wells drilled; the ability of the Company to achieve its objectives and goals; the application of regulatory and royalty regimes; the financial assumptions used by Surge's reserve evaluators in assessing potential impairment of Surge assets; Surge's belief that the majority of cash flow's associated with its proved and probable reserves will be realized prior to the elimination of carbon based energy; the Company's belief in the uncertainty regarding the ultimate period in which global energy markets can transition from carbon based sources to alternative energy; management's expectations as to the cause of fluctuation in corporate royalty rates; management's beliefs regarding the estimates of the future values for certain assets and liabilities of the Company; underlying causes of the fluctuations in Surge's revenue and net income (loss) from quarter to quarter; the Company's estimates with respect to incremental borrowing rates and lease terms; development and completion activities and the costs relating thereto; the performance of new wells and the ability of the Company to bring new wells on stream; the successful implementation of waterflood programs; the availability of and performance of facilities and pipelines; the geological characteristics of Surge's properties; and any acquired assets; the successful application of drilling, completion and seismic technology; the determination of decommissioning obligations; the ability to obtain approval from the syndicate to increase or maintain its credit facilities; the ability to continue borrowing under the Company's credit facilities and the syndicate's interpretation of the Company's obligations thereunder; ability of the Company to obtain alternative form of debt and equity financing on terms acceptable to the Company to meet its capital requirements; prevailing weather conditions; exchange rates; licensing requirements; the impact of completed facilities on operating costs; that prevailing regulatory, tax and environmental laws and regulations apply or are introduced as expected, and the timing of such introduction; and the availability of 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 $2.66 MM per well capital, has a payout of approximately 10 months at US$65/bbl WTI (C$83.33/bbl LSB) and an approximate 150 percent IRR.

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 June 30, 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 (income). 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 (income) represent expenditures associated with property acquisitions and dispositions, debt restructuring and employee severance costs as well as other income, 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:

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 (income), 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.

Free cash 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.

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.

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.

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:

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.