SURGE ENERGY INC. ANNOUNCES SECOND QUARTER 2026 FINANCIAL & OPERATIONAL UPDATES

SURGE ENERGY INC. ANNOUNCES SECOND QUARTER 2026 FINANCIAL & OPERATIONAL UPDATES

CALGARY, ALBERTA, July 29, 2026 /CNW/ -- Surge Energy Inc.("Surge" or the "Company") (TSX: SGY) is pleased to announce its financial and operating results for the quarter ended June 30,2026, as well as an update on the Company's latest operational achievements.

As a result of continued successful drilling and waterflood results in Surge's two core areas, on June 1, 2026 the Company upwardly revised its 2026 capital budget and production guidance. Surge's 2026 exit production guidance increased from 23,000 boepd to 24,000 boepd, and 2026 average production guidance increased from 23,000 boepd to 23,375 boepd. Budgeted capital expenditures for 2026 are now estimated to be $175 million, as compared to Surge's original capital guidance of $150 million, with $16 million of the incremental capital being allocated to additional drilling, and the remaining $9 million being directed towards accelerating Surge's waterflood programs, primarily focused in the Sparky core area. 

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, 2026, available on Surge's profile at www.sedarplus.ca and on Surge's website at www.surgeenergy.ca.

Q2/26 MESSAGE TO SHAREHOLDERS

Strong drilling results in the Company's Sparky and SE Saskatchewan core areas during 1H/26 continued to drive production outperformance, as compared to Surge's initial 2026 budget guidance press released on November 5, 2025. In 1H/26, Surge's production averaged 23,376 boepd (89 percent liquids), ahead of the Company's initial 23,000 boepd average production guidance for 2026.

In Q2/26, the spring break-up quarter, Surge's production averaged 22,865 boepd (89 percent liquids). During the quarter, the Company experienced normal spring break-up operations, including limited drilling (based on road bans), planned turnarounds, and wet spring weather conditions. Additionally, in Q2/26, Surge experienced an unplanned third-party gas plant outage for approximately five weeks in its Sparky core area, which impacted production volumes for the quarter by approximately 400 boepd. The third-party gas plant operator rectified this outage in mid-June, and all impacted production volumes are now back on stream.

With three rigs now operational, Surge remains on track to meet or exceed both the Company's upwardly revised average (23,375 boepd) and exit rate (24,000 boepd) production targets as announced on June 1, 2026.

During Q2/26, Surge generated adjusted funds flow ("AFF")¹ of $91.5 million ($0.92 per share), and cash flow from operating activities of $95.3 million ($0.95 per share). This represents an increase of 26 percent in AFF, as compared to Q2/25 AFF of $72.8 million, and a 69 percent increase in cash flow from operating activities, as compared to $56.3 million in Q2/25.

During Q2/26, the Company spent $32.8 million on property, plant, and equipment expenditures. On this basis, Surge generated $58.7 million in free cash flow ("FCF")¹ in the second quarter, representing 64 percent of Q2/26 AFF.

With the Company's longer-term primary corporate goals of maximizing FCF, enhancing shareholder returns, and reducing net debt, Surge's Board and Management allocated Q2/26 FCF to the following initiatives:

• $12.9 million to the Company's monthly cash dividend ($0.52 per share, per annum);
• $15.0 million towards share buybacks under Surge's Normal Course Issuer Bid ("NCIB"), repurchasing 1,564,300 shares;
• $16.7 million reduction in net debt¹, reducing net debt by 8 percent during the quarter, from $213.3 million as at March 31, 2026, to $196.6 million as at June 30, 2026; and
• $10.8 million of FCF was allocated to the strategic acquisition of the Hansman Lake gas plant, centrally located in the Sparky core area, which was previously leased by the Company. The Hansman Lake plant has 14 mmcf/d of capacity and controls a significant portion of the gas produced by both Surge and third parties in the Provost/Cadogan area. This acquisition of a 100 percent owned and operated gas plant in this core operating area is expected to increase Surge's FCF by an estimated $4.6 million annually, beginning in Q3/26.

Q2/26 AND 1H/26 FINANCIAL AND OPERATIONAL HIGHLIGHTS

Highlights from the Company's Q2/26 and 1H/26 financial and operating results include:

• Higher than initially budgeted average 1H/26 daily production of 23,376 boepd (89 percent liquids);
• Generated $91.5 million ($0.92 per share) of AFF in Q2/26, and cash flow from operating activities of $95.3 million ($0.95 per share);
• Decreased net operating expenses¹ by 6 percent, from $18.70 per boe in Q1/26 to $17.49 per boe in Q2/26;
• Distributed $12.9 million to shareholders by way of the Company's $0.52 per share per annum base dividend (paid monthly);
• Decreased net debt by $16.7 million, from $213.3 million as at March 31, 2026 to $196.6 million as at June 30, 2026;
• On an annualized basis, Q2/26 AFF represented 0.54 times exit Q2/26 net debt of $196.6 million; 
• Returned an additional $15.0 million to shareholders by way of the Company's ongoing NCIB program;
• Executed the strategic acquisition of Surge's key Hansman Lake gas plant, centrally located in the Company's Sparky core area; and
• Closed a 2-year extension of its first-lien credit facilities, consisting of an undrawn $225 million revolving credit facility as well as an uncommitted accordion feature which allows for a $25 million expansion, providing up to $250 million in total available credit facilities.

FINANCIAL AND OPERATING HIGHLIGHTS

OPERATIONS UPDATE: CONTINUED DRILLING AND WATERFLOOD SUCCESS IN SPARKY AND SE SASKATCHEWAN CORE AREAS

Surge's Q2/26 drilling program consisted of 12 gross (11.5 net) wells drilled during the quarter, comprised of the following:

• 4 gross (4.0 net) producing wells drilled in Sparky;
• 5 gross (5.0 net) dedicated injectors drilled in Sparky; and
• 3 gross (2.5 net) producing wells drilled in SE Saskatchewan.

Due to wet spring weather, only 4 of the producing wells were brought on production late in Q2/26, with the remaining wells being brought on production in Q3/26.

Sparky (Mannville) Waterflood and Operations Update

During oil extraction, reservoir pressure is depleted, leading to steeper declines and lower recovery factors of the original oil in place ("OOIP"). By injecting (often re-injecting) water into a conventional oil pool, the pressure in the reservoir can be sustained, reducing production declines and leading to higher recovery factors from the pool.

In addition to providing shareholders with top tier drilling economics, Surge's core area Sparky and SE Saskatchewan conventional reservoirs are very conducive to waterflood, which provides the Company and its shareholders with long term, incremental value from stable oil production and higher recovery factors.

Surge has continued to meaningfully expand the Company's waterflood capital program over the past several years, increasing waterflood spending from $2 million in 2024, to $8 million in 2025, to an initial budget of $12 million in 2026. On June 1, 2026, Surge further increased its 2026 waterflood capital program by an additional $9 million, to $21 million for 2026. This commitment to waterflood initiatives underscores the importance of enhanced oil recovery across the Company's asset base.

By the end of 2026, Surge anticipates that approximately 57 percent of the Company's total oil production will be supported by waterflood and natural aquifer drive mechanisms. This increased level of waterflood activity is a key driver in improving reservoir performance and enhancing ultimate recovery. As a result, the Company is targeting a systematic, longer-term reduction in its corporate decline rates, as expanded waterflood activities moderate declines and increase oil recoveries.

The development and delineation of Surge's Hope Valley discovery continued in Q2/26, with the drilling of five dedicated water injectors in section 19. These are in addition to the two dedicated injectors drilled in Q1/26 and the Company's first dedicated injector drilled in December 2025. As a result, Surge now has an expanded eight-injector waterflood pilot in the greater Hope Valley area, with four additional dedicated injectors planned for 2H/26.

Surge's initial pilot well, brought on in December 2025, is demonstrating encouraging initial results, with production rates stabilizing and gas‑oil ratios declining - both positive indicators of effective reservoir support and improved sweep efficiency. The Company anticipates providing a further operational update on its open hole multi-lateral ("OHML") waterflood pilot in Q3/26.

In addition, Surge has now successfully converted 7 single-leg horizontal wells to water injection in the Sparky formation at the Company's Provost/Cadogan, Sounding Lake, and Betty Lake fields, with 7 additional conversions planned for 2H/26.

Other core area conventional crude oil reservoirs where Surge operates successful waterfloods include Betty Lake, Sounding Lake, Wainwright, Giltedge, Freda Lake, Neptune, and Bryant.

At Provost/Cadogan, Surge continues to deliver better than type-curve Sparky well results² through the application of single-leg multi-frac drilling technology, utilizing additional frac stages combined with high-volume lift.

SE Saskatchewan (Frobisher) Operations Update

In SE Saskatchewan, Surge continued its momentum on these operated light oil assets with Q2/26 drilling primarily focused on multilateral wells targeting the Frobisher horizon. The Company drilled 3 gross (2.5 net) wells in this area during the second quarter, with 2 gross (2.0 net) wells having been brought on production late in Q2/26.

Surge's Frobisher drilling program continues to deliver strong production results in the Company's SE Saskatchewan core area, with an average IP90 production rate of 187 bopd over the 88 gross wells drilled since January 1, 2022².

Additionally, Surge's initial well drilled in Q4/25 at Freda Lake (in the Ratcliffe formation) continues to exceed type-curve expectations³, with more than 44,000 barrels of oil produced in the first six months. Surge has now internally identified more than 20 net additional light oil drilling locations³ at Freda Lake.

OUTLOOK: FOCUSED, PREMIUM ASSET QUALITY DRIVES SUPERIOR RETURNS

Continuing hostilities in the Middle East has seen crude oil prices increase from a recent low of US$68 WTI per barrel on July 6, 2026 to approximately US$84 WTI per barrel today and are expected to continue to fluctuate. The crude oil futures market has also reverted to backwardation, a historically bullish sign for future oil prices.

Surge's Board and Management continue to methodically implement the Company's disciplined capital allocation business strategy, with cash flow strategically allocated between focused, high rate of return capital investments, and returns to shareholders. Surge is currently returning over $51 million annually to shareholders through the Company's existing $0.52 per share per annum base dividend (paid monthly). Management anticipates allocating the majority of the Company's excess FCF towards continued reduction of net debt, as well as share repurchases under its existing NCIB program.

Surge's conventional crude oil asset base is now 92 percent focused in two of the top five crude oil plays in Canada⁴ based on per well payout economics, inclusive of its Sparky (>14,000 boepd; 86 percent medium gravity oil and liquids) and SE Saskatchewan (~7,500 boepd; 90 percent light oil and liquids) core areas.

Surge is focused on delivering shareholder returns in 2026 and beyond, based on the key corporate fundamentals set forth below:

• Estimated 2026 exit production of 24,000 boepd (89 percent liquids);
• Estimated 2026 average production of 23,375 boepd (89 percent liquids);
• Estimated 2026 AFF of $335 million⁵ ($3.39 per share);
• Estimated 2026 cash flow from operating activities of $320 million⁵ ($3.24 per share);
• A $51.5 million annual base cash dividend ($0.52 per share annual dividend, paid monthly), which represents approximately 15 percent of the Company's forecasted 2026 AFF of $335 million;
• An independently engineered total proved and probable NAV per share of $17.10⁶, based on a US$75 WTI flat price forecast;
• An undrawn, 2-year $225 million revolving credit facility and an uncommitted $25 million accordion, which provides up to $250 million in total available credit facilities;
• An internally estimated 25 percent annual corporate decline⁶;
• More than 900 (net) internally estimated drilling locations, providing a 12-year drilling inventory³; and
• $1.2 billion in tax pools (representing an estimated 4-year tax horizon)⁵.

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 2026 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 for the remainder of 2026; projections with respect to the Company's capital efficiencies; crude oil fixed price hedges protecting the Company's 2026 FCF profile; share repurchases under the Company's NCIB; expectations with respect to the Company's total oil production by the end of 2026; timing with respect to updates on the Company's OHML waterflood pilot; 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 2026 drilling program and focus, including expectations regarding the number of wells to be drilled and the types thereof; Surge's expectations with respect to well conversions in the Sparky area for the remainder of 2026; expectations with respect to Surge's application of single-leg multi-frac drilling technology, utilizing additional frac stages combined with high-volume lift; Surge's 2026 capital program and focus; expectations with respect to Surge's allocation of FCF; Surge's focus on delivering shareholder returns in 2026 and its key corporate fundamentals; 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 second half of 2026 and the number of wells to be drilled thereat; management's belief that Surge is well positioned to deliver attractive shareholder returns; and management's expectations regarding Surge's 2026 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; Surge's key drivers in improving reservoir performance and enhancing ultimate recovery; expectations with respect to its key corporate fundamentals underlying shareholder returns; 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 forms 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 Annual Information Form dated March 4, 2026 and in Surge's Management's Discussion & Analysis for the year ended December 31, 2025, both of which have been filed on SEDAR+ and can be accessed on Surge's profile 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:

"Original oil in place (OOIP)" refers to the initial volume of oil present in the reservoir at the time of its formation.

"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 (March 2025 to March 2026), without new drilling. GLJ Ltd. ("GLJ") 2025YE reserves have a PDP decline of 25 percent and a P+PDP decline of 23 percent.

"Net Asset Value (NAV)" is calculated as reserve value discounted at 10 percent on a BTax basis, less the Company's net debt, a non-GAAP financial measure, at December 31, 2025 of $220.6 million and is divided by 98.9 million shares outstanding as at December 31, 2025.

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 Engineers and Geologists (and have been reviewed by Surge's Qualified Reserve Evaluators) 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, 2026 reference date, the Company will have over >1,000 gross (>900 net) drilling locations identified herein; of these >600 gross (>525 net) are unbooked locations. Of the 361 net booked locations identified herein, 282 net are Proved locations and 78 net are Probable locations based on GLJ's 2025YE reserves. Assuming an average number of net wells drilled per year of 65, Surge's >900 net locations provide 13 years of drilling.

Assuming a January 1, 2026 reference date, the Company will have over >500 gross (>500 net) Sparky Core area drilling locations identified herein; of these >300 gross (>300 net) are unbooked locations. Of the 191 net booked locations identified herein, 142 net are Proved locations and 50 net are Probable locations based on GLJ's 2025YE reserves. Assuming an average number of wells drilled per year of 35, Surge's >500 net locations provide >14 years of drilling.

Assuming a January 1, 2026 reference date, the Company will have over >325 gross (>300 net) SE Saskatchewan drilling locations identified herein; of these >170 gross (>145 net) are unbooked locations. Of the 143 net booked locations identified herein, 115 net are Proved locations and 29 net are Probable locations based on GLJ's 2025YE reserves. Assuming an average number of wells drilled per year of 30, Surge's >300 net locations provide >10 years of drilling.

Assuming a January 1, 2026 reference date, the Company will have 22 gross (21.5 net) Ratcliffe SE Saskatchewan drilling locations identified herein; of these 16 gross (16.0 net) are unbooked locations. Of the 5.5 net booked locations identified herein, 3.5 net are Proved locations and 2.0 net are Probable locations based on GLJ's 2025YE reserves. 

Surge's internally used type curves were constructed using a representative, factual and balanced analog data set, as of January 1, 2026. All locations were risked appropriately, and EUR's were measured against OOIP 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 (and reviewed by Surge's Qualified Reserve Evaluators). All type curves fully comply with Part 5.8 of the Companion Policy 51 – 101CP. 

Over the past 18 months the Company has successfully implemented high-density frac technology (doubling the stages per well), drilling 20 gross (20 net) single lateral multi-frac wells in the Sparky core area. In Provost, this strategic modification to Surge's frac design has resulted in a >50 percent increase in IP90 average production rates (from 94 bopd to 211 bopd on a 1P basis, and from 118 bopd to 210 bopd on a 2P basis) and a >20 percent increase in average oil EUR bookings (from 82 Mstb to 107 Mstb on a 1P basis, and from 110 Mstb to 148 Mstb on a 2P basis). The cost increase associated with this is approximately 15 percent ($0.3 million per well) in the Company's independent reserve auditor type curve as compared to the standard stage spacing bookings.

The Company's initial well drilled in Q4/25 at Freda Lake in the Ratcliffe formation (103/09-23-004-18W2/00) had an IP180 production rate of 244 bblpd. These IP results are >500 percent better than the Company's independent reserve auditor IP180 Proved Undeveloped (PUD) type curve expectations of 47 bblpd (137 mbbl EUR).

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 capital management measures, non-GAAP financial measures and non-GAAP ratios and are not defined by IFRS Accounting Standards ("IFRS") and therefore are referred to as non-GAAP and other financial measures. Certain secondary financial measures in this press release are not prescribed by GAAP. 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, 2026, have been provided to demonstrate the calculation of these measures:

Adjusted Funds Flow & Adjusted Funds Flow Per Share

AFF is a capital management measure. The Company adjusts cash flow from operating activities in calculating AFF 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.

AFF per share is a supplementary financial measure, 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 AFF per share:

Free Cash Flow

FCF is a non-GAAP financial measure. FCF 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 FCF to determine the amount of funds available to the Company for future capital allocation decisions.

Net Debt

Net debt is a capital management 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. 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. This metric is used by Management to evaluate the Company's ability to generate cash margin on a unit of production basis.

AFF 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 and AFF 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.