SURGE ENERGY INC. ANNOUNCES RECORD PRODUCTION LEVELS IN Q1/23; FINANCIAL & OPERATING RESULTS FOR Q1/23; AND AN OPERATIONS UPDATE ON DRILLING RESULTS IN SPARKY AND SE SASKATCHEWAN CORE AREAS

CALGARY, AB, May 3, 2023 /CNW/ - Surge Energy Inc. ("Surge" or the "Company") (TSX: SGY) is pleased to announce the Company's financial and operating results for the quarter ended March 31, 2023, and an update on Surge's latest drilling results.

Q1 2023 FINANCIAL & OPERATING HIGHLIGHTS

SURGE& ENERGY& INC.& ANNOUNCES RECORD PRODUCTION LEVELS IN Q1/23; FINANCIAL& && OPERATING& RESULTS FOR Q1/23; AND AN OPERATIONS UPDATE ON DRILLING RESULTS IN SPARKY AND SE SASKATCHEWAN CORE AREAS (CNW Group/Surge Energy Inc.)

Q1/23 is the Company's first quarter that includes the full impact of the strategic acquisition of high quality, core area assets from Enerplus (the "Acquisition"), which closed in late Q4/22. In Q1/23 Surge delivered an increase in production of more than 22 percent compared to Q1/22, with production increasing from 20,550 boepd (85 percent liquids) to a record 25,138 boepd (87 percent liquids) in the current quarter. Surge's December 31, 2023 production exit rate guidance is 25,000 boepd.

West Texas Intermediate ("WTI") crude oil prices in Q1/23 decreased by more than 19 percent (i.e. a drop of over US$18 per barrel) compared to Q1/22. Additionally, Western Canadian Select ("WCS") differentials to WTI also widened substantially in Q1/23, resulting in a benchmark WCS crude oil price of C$69.46 per barrel, a decrease of 31 percent compared to a Q1/22 WCS price of C$101.01 per barrel. The WCS differential to WTI in Q1/23 was US$24.79 per barrel. Approximately fifty percent of Surge's crude oil production is correlated to WCS pricing.

Encouragingly, WCS differentials have quickly returned to long term historical levels, with both April, 2023 and May, 2023 WCS differentials settling below US$16 per barrel. Surge Management is optimistic that WCS differentials could even improve beyond these levels as the Trans Mountain pipeline expansion project comes online (currently forecast for early 2024).

Despite the much lower crude oil price environment experienced during the quarter, Surge's cash flow from operating activities increased by four percent to $54.5 million in Q1/23, up from $52.2 million in Q1/22. Furthermore, after adjusting for changes in non-cash working capital, the Company delivered adjusted funds flow¹ ("AFF") of $63.3 million in Q1/23, which represents an increase of one percent compared to Q1/22 AFF of $62.9 million.

These positive financial results are primarily due to the accretive Acquisition, Surge's exciting Frobisher light oil drilling results in SE Saskatchewan, and the expiry of the Company's previously mandated 2022 fixed price crude oil hedges.

During the quarter, Surge returned $11.7 million to its shareholders in the form of cash dividends pursuant to the Company's base cash dividend of $0.48 per share per annum (paid monthly). The cash dividends paid during the quarter represent less than 19 percent of Surge's Q1/23 AFF.

Additional highlights from the Company's Q1/23 financial and operating results include:

• Reported Surge's first complete quarter including the Acquisition, with production from the acquired assets contributing approximately 3,800 boepd (99 percent liquids) to Q1/23 production;
• Achieved record average daily production of 25,138 boepd (87 percent liquids) during Q1/23, an increase of over 22 percent compared to Q1/22 production of 20,550 boepd (85 percent liquids);
• Successfully drilled 18 gross (17.9 net) wells, with activity focused in the Company's Sparky and SE Saskatchewan conventional light and medium gravity crude oil core areas; and
• Announced that the Company's independently engineered December 31, 2022 (Sproule) Proven Developed Producing ("PDP") Net Asset Value ("NAV") increased by 107 percent year over year, from $3.51 per share to $7.27 per share.

FINANCIAL AND OPERATING HIGHLIGHTS 

FINANCIAL AND OPERATING HIGHLIGHTS	Three Months Ended March 31,
($000s except per share amounts)	2023	2022	% Change
Financial highlights
Oil sales	152,664	157,440	(3) %
NGL sales	3,618	4,053	(11) %
Natural gas sales	5,688	7,631	(25) %
Total oil, natural gas, and NGL revenue	161,970	169,124	(4) %
Cash flow from operating activities	54,506	52,182	4 %
Per share - basic ($)	0.56	0.63	(11) %
Per share diluted ($)	0.55	0.63	(13) %
Adjusted funds flow^a	63,331	62,893	1 %
Per share - basic ($)^a	0.65	0.75	(13) %
Per share diluted ($)	0.64	0.75	(15) %
Net income (loss)	14,789	(21,868)	nm^b
Per share basic ($)	0.15	(0.26)	nm
Per share diluted ($)	0.15	(0.26)	nm
Expenditures on property, plant and equipment	45,733	42,968	6 %
Net acquisitions and dispositions	(678)	—	nm
Net capital expenditures	45,055	42,968	5 %
Net debt^a, end of period	331,917	315,770	5 %
Operating highlights
Production:
Oil (bbls per day)	21,055	16,760	26 %
NGLs (bbls per day)	721	691	4 %
Natural gas (mcf per day)	20,172	18,592	8 %
Total (boe per day) (6:1)	25,138	20,550	22 %
Average realized price (excluding hedges):
Oil ($ per bbl)	80.57	104.38	(23) %
NGL ($ per bbl)	55.78	65.17	(14) %
Natural gas ($ per mcf)	3.13	4.56	(31) %
Netback ($ per boe)
Petroleum and natural gas revenue	71.59	91.45	(22) %
Realized gain (loss) on commodity and FX contracts	(0.88)	(15.58)	(94) %
Royalties	(12.84)	(15.36)	(16) %
Net operating expenses^a	(22.26)	(19.28)	15 %
Transportation expenses	(1.79)	(1.50)	19 %
Operating netback^a	33.82	39.73	(15) %
G&A expense	(2.04)	(2.18)	(6) %
Interest expense	(3.80)	(3.55)	7 %
Adjusted funds flow^a	27.98	34.00	(18) %
Common shares outstanding, end of period	98,334	83,357	18 %
Weighted average basic shares outstanding	97,087	83,357	16 %
Stock based compensation dilution	2,296	—	100 %
Weighted average diluted shares outstanding	99,383	83,357	19 %
^a This is a non-GAAP and other financial measure which is defined in the Non-GAAP and Other Financial Measures section of this document.
^b The Company views this change calculation as not meaningful, or "nm".

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

Surge continued its strong operational momentum in Q1/23, with a drilling rig active in each of its Sparky and SE Saskatchewan core areas. The Company budgets drilling 67.0 net wells in 2023, with this program comprised of 37.0 net Sparky wells and 30.0 net SE Saskatchewan wells. The Company plans to commence its post-breakup drilling program in both the Sparky and SE Saskatchewan core areas on or about June 1, 2023.

During Q1/23, Surge successfully drilled a total of 18 gross (17.9 net) wells, spending a total of $45.7 million including expenditures on property, facilities, and equipment. Q1/23 capital expenditures were in line with the Company's budget estimates. Drilling operations during the first quarter focused on Surge's medium and light gravity crude oil assets in its Sparky and SE Saskatchewan core areas.

In the Company's Sparky core area, Surge drilled 10 gross (10.0 net) wells in the first quarter of 2023 with a 100 percent success rate (the average IP30 of the 10 well program being greater than 125 bbl/d²). Two gross (2.0 net) of these 10 wells were drilled on lands located in the recently acquired Cadogan property, which was obtained through the Enerplus Acquisition. These two Sparky wells are still cleaning up and are currently producing at a combined rate of 300 bopd. Surge has identified an internally estimated 32.0 net follow up Sparky drilling locations²  on the acquired Cadogan property alone.

Surge's current Sparky core area production now exceeds 11,000 boepd (>85 percent liquids; 25° API average oil quality) for the first time in the Company's history, up over 800 percent from 1,200 boepd eight years ago. Surge has a 12 year Sparky drilling inventory of more than 480 internally estimated drilling locations², as well as attractive waterflood upside.

In Q1/23, Surge drilled 8 gross (7.9 net) wells in the Company's SE Saskatchewan core area. Drilling operations primarily targeted light oil in the prolific Frobisher formation. The average Surge SE Saskatchewan well drilled in Q1/23 came on production with an IP30 of more than 250 boepd (90 percent light oil). Surge's average internal Frobisher type curve has an IP30 of 240 boepd and a payout of approximately 11 weeks at US$80 WTI flat pricing².

Surge continues to add significant organic drilling inventory in SE Saskatchewan, and now has an inventory of more than 275.0 net drilling locations, with more than 160.0 net locations targeting the prolific Frobisher horizon.

Since the start of 2023, Surge has continued to execute on the Company's organic land acquisition strategy, adding 4.0 net sections and 28 gross (28.0 net) drilling locations³ through Crown land sales and freehold leasing. Included in this are 14.0 net drilling locations on the Frobisher trend in SE Saskatchewan. Surge intends to drill 4 gross (4.0 net) wells on these newly acquired lands in 2023.

OUTLOOK: POSITIONED FOR SUCCESS IN 2023 AND BEYOND

Surge is a 25,000 boepd (87 percent liquids) intermediate, publicly traded oil company that is focused on enhancing shareholder returns through free cash flow generation. The Company's defined operating strategy is based on acquiring and developing high quality, conventional, light and medium gravity crude oil reservoirs, using proven technology to enhance ultimate oil recoveries.

With more than 3.0 billion barrels of net (internally estimated) original oil in place ("OOIP")⁴, a low 7.7 percent recovery factor at year end 2022, and a dominant operational position in two of the most economic⁵ light and medium gravity crude oil plays in Canada, Surge believes that the Company is poised to deliver strong results both operationally and financially in 2023 and beyond.

In addition, with over $1.4 billion in estimated tax pools at December 31, 2022, Surge is committed to delivering its shareholders a combination of:

• continued net debt repayment (increasing Surge's NAV per share);
• a $0.48 per share annual base cash dividend, paid monthly;
• share buybacks;
• a modest production per share growth wedge; and
• potential for variable or special dividends.

FORWARD LOOKING STATEMENTS

This press release contains forward-looking statements. The use of any of the words "anticipate", "continue", "estimate", "expect", "may", "will", "project", "should", "believe" 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 expectations regarding crude oil prices and WCS differentials; its plans to commence its post-breakup drilling program and the timing thereof;  its focus and defined operating strategy; management's belief that Surge is poised to deliver strong results both operationally and financially in 2023 and beyond; its estimated tax pools; and its forecast for achievement of its Phase 2 return to capital net debt target; management's belief that Surge is well positioned to deliver to its shareholders a combination of continued net debt repayment; a $0.48 per share annual base cash dividend, paid monthly; share buybacks; a modest production per share growth wedge; and potential for variable or special dividend; sits 2023 guidance, including its 2023 estimates for average production; expenditures on plant, property and equipment; cash flow from operating activities; dividends and dividends per share; royalties as a percentage of petroleum and natural gas revenue; net operating expenses; transportation expenses and general and administrative expenses.

The forward-looking statements are based on certain key expectations and assumptions made by Surge, including expectations and assumptions around 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; 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 (including the impact of COVID-19) 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; 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 8, 2023 and in Surge's MD&A for the period ended December 31, 2022, both of which have been filed on SEDAR and can be accessed at www.sedar.com.

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

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.

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.

Original Oil in Place ("OOIP") means Discovered Petroleum Initially In Place ("DPIIP"). DPIIP is derived by Surge's internal Qualified Reserve Evaluators ("QRE") and prepared in accordance with National Instrument 51-101 and the Canadian Oil and Gas Evaluations Handbook ("COGEH"). DPIIP, as defined in COGEH, is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of DPIIP includes production, reserves and Resources Other Than Reserves (ROTR). OOIP/DPIIP and potential recovery rate estimates are based on current recovery technologies. There is significant uncertainty as to the ultimate recoverability and commercial viability of any of the resource associated with OOIP/DPIIP, and as such a recovery project cannot be defined for a volume of OOIP/DPIIP at this time. "Internally estimated" means an estimate that is derived by Surge's internal QRE's and prepared in accordance with National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities. All internal estimates contained in this new release have been prepared effective as of January 1, 2023.

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 internal evaluation using standard practices as prescribed in COGEH 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) 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 any or 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, 2023 reference date, the Company will have over >1,150 gross (>1,050 net) drilling locations identified herein; of these >625 gross (>575 net) are unbooked locations. Of the 489 net booked locations identified herein, 366 net are Proved locations and 122 net are Probable locations based on Sproule's 2022YE reserves. Assuming an average number of wells drilled per year of 80, Surge's >1,050 net locations provide 13 years of drilling.

Assuming a January 1, 2023 reference date, the Company will have over >480 gross (>480 net) Sparky Core area drilling locations identified herein; of these >300 gross (>300 net) are unbooked locations. Of the 182 net booked locations identified herein, 126 net are Proved locations and 56 net are Probable locations based on Sproule's 2022YE reserves. Assuming an average number of wells drilled per year of 40, Surge's >480 net locations provide >12 years of drilling.

Assuming a January 1, 2023 reference date, the Company will have over >325 gross (>275 net) SE Sask drilling locations identified herein; of these >140 gross (>120 net) are unbooked locations. Of the 154 net booked locations identified herein, 105 net are Proved locations and 49 net are Probable locations based on Sproule's 2022YE reserves.  Assuming an average number of wells drilled per year of 40, Surge's >275 net locations provide ~7 years of drilling.

Assuming subset of SE Sask inventory, and a January 1, 2023 reference date, the Company will have over >190 gross (>160 net) SE Sask Frobisher drilling locations identified herein; of these >80 gross (>75 net) are unbooked locations. Of the 89 net booked locations identified herein, 56 net are Proved locations and 33 net are Probable locations based on Sproule's 2022YE reserves.

Surge's internally used type curves were constructed using a representative, factual and balanced analog data set, as of January 1, 2023. All locations were risked appropriately, and EURs 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 by Surge's Qualified Reserve Evaluators. All type curves fully comply with Part 5.8 of the Companion Policy 51 – 101CP.

The average production profile from the initial 2023, 10 net SPKY well program was 127 bbl/d vs Surge's internal average Sparky type curve profile of 107 bbl/d (IP30) and 120 mboe (108 mbbl Oil + 3 mbbl NGL's) Estimated Ultimate Recoverable reserves per well, has a payout of 9 months @ US$80/bbl WTI (C$88/bbl WCS). 

Surge's average internal Frobisher type curve (Steelman land sale) economics have a payout of 11 weeks @ US$80/bbl WTI (~C$103/bbl LSB) and are supported by >125 internally evaluated Frobisher locations by Surge's Qualified Reserve Evaluators, with average metrics of: ~$1.3 MM per well capital, ~240 boe/d IP30 per well and ~89 mboe (69 mbbl Oil + 12 mbbl NGL's) Estimated Ultimate Recoverable reserves per well). 

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, are not defined by IFRS and therefore are referred to as non-GAAP and other financial measures. Certain secondary financial measures in this press release – namely "adjusted funds flow", "adjusted funds flow per share", "net debt", "net operating expenses", "net operating expenses per boe", "operating netback", "operating netback per boe", and "adjusted funds flow per boe" 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.

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 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 amounts)	2023	2022
Cash flow from operating activities	54,506	52,182
Change in non-cash working capital	5,445	9,061
Decommissioning expenditures	3,249	1,495
Cash settled transaction and other costs	131	155
Adjusted funds flow	$                        63,331	$                        62,893
Per share - basic	$                            0.65	$                            0.75

Net Debt

Net debt is a non-GAAP financial measure, calculated as bank debt, 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, 2023	As at Dec 31, 2022	As at Mar 31, 2022
Accounts receivable	64,642	60,623	83,502
Prepaid expenses and deposits	4,340	3,032	3,669
Accounts payable and accrued liabilities	(89,094)	(93,373)	(97,913)
Dividends payable	(3,933)	(3,375)	—
Bank debt	(27,345)	(30,597)	(96,780)
Term debt	(247,724)	(256,032)	(133,580)
Convertible debentures	(32,803)	(32,491)	(74,668)
Net Debt	(331,917)	(352,213)	(315,770)

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,
($000s)	2023	2022
Operating expenses	52,892	37,454
Less: processing income	(2,534)	(1,806)
Net operating expenses	50,358	35,648
Net operating expenses ($ per boe)	$                          22.26	$                          19.28

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,
($000s)	2023	2022
Petroleum and natural gas revenue	161,970	169,124
Processing and other income	2,534	1,806
Royalties	(29,042)	(28,401)
Realized loss on commodity and FX contracts	(1,995)	(28,809)
Operating expenses	(52,892)	(37,454)
Transportation expenses	(4,047)	(2,777)
Operating netback	76,528	73,489
G&A expense	(4,610)	(4,032)
Interest expense	(8,587)	(6,564)
Adjusted funds flow	63,331	62,893
Barrels of oil equivalent (boe)	2,262,361	1,849,429
Operating netback ($ per boe)	$                          33.82	$                          39.73
Adjusted funds flow ($ per boe)	$                          27.98	$                          34.00

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.

______________________________

¹ This is a non-GAAP and other financial measure which is defined in the Non-GAAP and Other Financial Measures section of this document.

² See Drilling Inventory section in the Forward Looking Statements.

³ Surge's Qualified Reserve Evaluators estimate there are 14.0 net FRBR, and 14.0 net SPKY locations.

⁴ See Oil and Gas Advisories section in the Forward Looking Statements

⁵ As per Peters Oil & Gas Plays Update from January 9, 2023: North American Oil and Natural Gas Plays – Half Cycle Payout Period.  Note: Sparky is represented as "Conventional Heavy Oil Hz" by Peters.

SOURCE Surge Energy Inc.

Paul Colborne, President & CEO, [phone], [email protected]; Jared Ducs, Chief Financial Officer, [phone], [email protected]