Surge Energy Inc. — Management Reports 2021

Mar 9, 2021

FINANCIAL AND OPERATING SUMMARY

($000s except per share amounts)

	Three Months Ended				Years Ended December 31,
	Dec 31, 2020	Sep 30, 2020	% Change	2020	2019	% Change
Financial highlights
Oil sales	55,565	54,000	3 %	199,208	376,238	(47) %
NGL sales	1,745	1,161	50 %	4,613	8,109	(43) %
Natural gas sales	2,597	1,770	47 %	7,228	10,002	(28) %
Total oil, natural gas, and NGL revenue	59,907	56,931	5 %	211,049	394,349	(46) %
Cash flow from operating activities	11,000	15,082	(27) %	72,190	149,417	(52) %
Per share - basic ($)	0.03	0.04	(25) %	0.21	0.47	(55) %
Adjusted funds flow1	8,467	12,523	(32) %	59,872	172,988	(65) %
Per share - basic ($)1	0.02	0.04	(50) %	0.18	0.55	(67) %
Net loss	(57,727)	(13,184)	338 %	(747,297)	(158,664)	371 %
Per share basic ($)	(0.17)	(0.04)	325 %	(2.22)	(0.50)	344 %
Total exploration and developmentexpenditures	14,276	2,477	476 %	52,773	119,465	(56) %
Total acquisitions & dispositions	—	(762)	(100) %	(6,038)	(42,438)	(86) %
Total capital expenditures	14,276	1,715	732 %	46,735	77,027	(39) %
Net debt1, end of period	381,023	369,993	3 %	381,023	382,309	— %
Operating highlights
Production:
Oil (bbls per day)	13,788	13,759	— %	14,558	17,127	(15) %
NGLs (bbls per day)	726	582	25 %	600	692	(13) %
Natural gas (mcf per day)	17,050	16,503	3 %	16,906	20,135	(16) %
Total (boe per day) (6:1)	17,356	17,092	2 %	17,976	21,175	(15) %
Average realized price (excludinghedges):
Oil ($ per bbl)	43.80	42.66	3 %	37.39	60.19	(38) %
NGL ($ per bbl)	26.14	21.68	21 %	21.00	32.09	(35) %
Natural gas ($ per mcf)	1.66	1.17	42 %	1.17	1.36	(14) %
Netback ($ per boe)
Petroleum and natural gas revenue	37.52	36.21	4 %	32.08	51.02	(37) %
Realized gain (loss) on commodity andFX contracts	(3.91)	(1.67)	134 %	3.05	(0.61)	(600) %
Royalties	(4.07)	(4.00)	2 %	(3.72)	(6.71)	(45) %
Net operating expenses1	(15.99)	(14.16)	13 %	(14.72)	(14.50)	2 %
Transportation expenses	(1.18)	(1.39)	(15) %	(1.48)	(1.54)	(4) %
Operating netback1	12.37	14.99	(17) %	15.21	27.66	(45) %
G&A expense	(1.86)	(1.91)	(3) %	(1.90)	(1.85)	3 %
Interest expense	(5.21)	(5.11)	2 %	(4.20)	(3.45)	22 %
Adjusted funds flow1	5.30	7.97	(34) %	9.11	22.36	(59) %
Common shares outstanding, end ofperiod	339,785	339,785	— %	339,785	326,330	4 %
Weighted average basic sharesoutstanding	339,785	337,115	1 %	336,052	316,639	6 %
Weighted average diluted sharesoutstanding	339,785	337,115	1 %	336,052	316,639	6 %

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

MANAGEMENT'S DISCUSSION AND ANALYSIS

This Management's Discussion and Analysis ("MD&A") of the consolidated financial position and results of operations of Surge Energy Inc. ("Surge" or the "Company"), which includes its subsidiaries and partnership arrangements, is for the three months and years ended December 31, 2020 and 2019. For a full understanding of the financial position and results of operations of the Company, the MD&A should be read in conjunction with the documents filed on SEDAR, including historical financial statements, MD&A and the Annual Information Form ("AIF"). These documents are available at www.sedar.com.

Surge's management is responsible for the integrity of the information contained in this report and for the consistency between the MD&A and financial statements. In the preparation of these financial statements, estimates are necessary to make a determination of future values for certain assets and liabilities. Management believes these estimates have been based on careful judgments and have been properly presented. The financial statements have been prepared using policies and procedures established by management and fairly reflect Surge's financial position and results of operations. Surge's financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS").

Matters Relating to the COVID-19 Pandemic

In March 2020, the COVID-19 outbreak was declared a pandemic by the World Health Organization. In addition, global commodity prices declined significantly due to a collapse in demand attributed to COVID-19 in combination with an oversupply of oil. Governments worldwide, including those in Canada, have enacted emergency measures to combat the spread of the virus. These measures, which include the implementation of travel bans, self-imposed quarantine periods and physical distancing, have caused material disruption to businesses globally, resulting in an economic slowdown. Governments and central banks have reacted with significant monetary and fiscal interventions designed to stabilize economic conditions, however the success of these interventions is not currently determinable. The current economic environment may have significant adverse impacts on the Company including, but not limited to:

• Material declines in revenue and cash flows as a result of the decline in commodity prices;
• Declines in revenue and cash flows due to a reduced capital program and shut-in production;
• Increased impairment charges;
• Inability to comply with restrictions in lending agreements;
• Increased risk of non-performance by the Company's customers which could materially increase the risk of nonpayment of accounts receivable and customer defaults;
• Increased restructuring charges as the Company aligns its structure and personnel to the dynamic environment; and
• If the situation continues for prolonged periods it could jeopardize the Company's ability to continue as a going concern.

The situation is dynamic and the ultimate duration and magnitude of the impact on the economy and the financial effect on the Company is not known at this time. Estimates and judgments made by management in the preparation of these financial statements are increasingly difficult and subject to a higher degree of measurement uncertainty during this volatile period.

At the forward pricing scenarios experienced in 2020, exploration and production companies in Canada did not conform to the standard reserve-based lending ("RBL") structures. The Federal Government acknowledged the challenges facing the oil and gas industry and announced support programs intended to provide a liquidity backstop to RBL credit facilities administered through the Export Development Bank of Canada ("EDC") and the Business Development Bank of Canada ("BDC"). EDC and BDC worked directly with the primary banking institutions to provide additional lending and credit capacity to qualifying oil and gas producers that (based on certain criteria) were deemed financially viable prior to the onset of the COVID-19 pandemic. In November of 2020, the Company met the criteria for support under the announced programs. EDC joined the Company's syndicated RBL credit facility and the Company secured a four year, non-revolving second lien Term facility, maturing on November 17, 2024 under the BDC's Business Credit Availability Program Mid-Market Financing Program (refer to note 8 "Debt" in the financial statements for additional information).

Going Concern

As at December 31, 2020, the Company had $260.9 million drawn on a total commitment of $335.0 million available under its syndicated RBL credit facility. The facility is comprised of a $155.0 million revolving term commitment, a $167.5 million non-revolving term commitment, and a $12.5 million operating loan facility (refer to note 8 "Debt" in the financial statements for additional information). The revolving term commitment will continue to revolve until the next scheduled borrowing base redetermination date of June 30, 2021. The further extension of the credit facility is dependent on the Company's ability to repay or extend the term of the $167.5 million non-revolving term commitment that matures and requires repayment on December 31, 2021. Management is working with its syndicate of lenders to address the nonrevolving term commitment and extend the maturity date of the credit facility, however there can be no assurances with respect thereto. Should the Company fail to secure an extension, it could result in a failure to meet the terms of the lending agreement and the lender would have the right, but not the obligation, to demand repayment of amounts drawn on the credit facility. If the amount drawn is demanded and not repaid, this would constitute a default under the credit facility. A default under the credit facility would also constitute a default under the unsecured convertible debentures thereby allowing the holders to demand repayment of amounts outstanding.

The Company's ability to continue as a going concern is dependent upon the Company's ability to maintain the credit facility at or above amounts currently drawn and its ability to renew the credit facility prior to its repayment/maturity date. There can be no assurances that the facility will be renewed or additional sources of funding will be available for the Company. These matters cause material uncertainty which may cast significant doubt on the Company's ability to continue as a going concern.

Subsequent to December 31, 2020, the Company reached an agreement in principle with its respective lender syndicates to re-determine its first and second lien credit facilities (refer to note 20 "Subsequent Events" in the financial statements for additional information).

The consolidated financial statements do not reflect adjustments that would be necessary if the going concern assumption were not appropriate. If the going concern assumption were not appropriate, adjustments would be necessary in the carrying value of the Company's assets and liabilities, the reported revenues and expenses, and the balance sheet classifications used. These adjustments could be material.

Evolving Demand for Energy

The Company has considered the impact of the evolving worldwide demand for energy and global advancement of alternative sources of energy that are not sourced from fossil fuels in its assessment of impairment of its oil and gas properties. The measurement of impairment on the Company's oil and gas properties was based on proved and probable reserves, the life of which is generally less than 20 years. At December 31, 2020, a specific adjustment to the recoverable amount to account for the risk of the evolving demand for energy was not considered necessary, however, the recoverable amount is based on an estimated period of cash flows that indirectly reflects changing energy demands and the discount rate applied in the impairment test incorporates the current cost of capital in the energy industry which indirectly reflects current market trends around the evolving demand for energy and climate change. The ultimate period in which global energy markets can transition from carbon based sources to alternative energy is highly uncertain.

Surge's Board of Directors and Audit Committee have reviewed and approved the financial statements and MD&A. This MD&A is dated March 9, 2021.

DESCRIPTION OF BUSINESS

Surge is a Calgary based company that is engaged in the exploration, development and production of oil and gas from properties in western Canada. Surge's common shares are traded on the Toronto Stock Exchange ("TSX") under the symbol SGY.

	Three Months Ended				Years Ended Dec 31,
($000s except per share and per boe)	Dec 31, 2020	Sep 30, 2020	Dec 30, 2019	2020	2019
Cash flow from operating activities	11,000	15,082	34,474	72,190	149,417
Per share - basic ($)	0.03	0.04	0.11	0.21	0.47
Per share - diluted ($)	0.03	0.04	0.11	0.21	0.47
$ per boe	6.89	9.59	18.44	10.97	19.33
Adjusted funds flow	8,467	12,523	38,881	59,872	172,988
Per share - basic ($)	0.02	0.04	0.12	0.18	0.55
Per share - diluted ($)	0.02	0.04	0.12	0.18	0.55
$ per boe	5.30	7.97	20.80	9.11	22.36

CASH FLOW FROM OPERATING ACTIVITIES AND ADJUSTED FUNDS FLOW

Cash flow from operating activities for the fourth quarter of 2020 decreased 27 percent when compared to the third quarter of 2020 and decreased 68 percent when compared to the fourth quarter of 2019. On a per basic share basis, cash flow from operating activities decreased 25 percent compared to the third quarter of 2020 and decreased 73 percent compared to the fourth quarter of 2019. Cash flow from operating activities for the year ended December 31, 2020 decreased 52 percent when compared to the same period of the prior year and decreased 55 percent on a per basic share basis.

Adjusted funds flow for the fourth quarter of 2020 decreased 32 percent when compared to the third quarter of 2020 and decreased 78 percent when compared to the fourth quarter of 2019. On a per basic share basis, adjusted funds flow decreased 50 percent when compared to the third quarter of 2020 and decreased 83 percent compared to the fourth quarter of 2019. Adjusted funds flow for the year ended December 31, 2020 decreased 65 percent when compared to the same period of the prior year and decreased 67 percent on a per basic share basis.

Cash flow from operating activities and adjusted funds flow for the fourth quarter of 2020 decreased when compared to the immediate preceding quarter primarily due to the increase in realized loss on financial contracts and increase in operating expenses, partially offset with the increase in petroleum and natural gas revenue. The decrease in cash flow from operating activities and adjusted funds flow for the three months and year ended December 31, 2020 when compared to the same periods of the prior year is primarily a result of a decrease in petroleum and natural gas revenue and increase in interest expense.

See the following Operations section for additional information regarding the cash flow and operating results of the Company for the three months and year ended December 31, 2020 and see the Non-GAAP Financial Measures section of this MD&A for further information regarding adjusted funds flow.

OPERATIONS

Drilling

	Drilling		Success	Working
	Gross	Net	rate (%) net	interest (%)
Q1 2020	19.0	19.0	100 %	100 %
Q2 2020	—	—	—	—
Q3 2020	—	—	—	—
Q4 2020	13.0	13.0	100	100
Total	32.0	32.0	100 %	100 %

Effective March 2020, the Company suspended all major capital expenditures providing for an increased level of operational and financial flexibility for the balance of 2020. As such, no wells were drilled during the second and third quarters of 2020.

Surge achieved a 100 percent success rate during the year ended December 31, 2020, drilling 32 gross (32.0 net) wells. During the fourth quarter of 2020, Surge drilled 13 gross (13.0 net) wells in southeast Alberta ("Sparky").

		Three Months Ended	Years Ended Dec 31,
	Dec 31, 2020	Sep 30, 2020	Dec 31, 2019	2020	2019
Oil (bbls per day)	13,788	13,759	16,441	14,558	17,127
NGL (bbls per day)	726	582	630	600	692
Oil and NGL (bbls per day)	14,514	14,341	17,071	15,158	17,819
Natural gas (mcf per day)	17,050	16,503	19,521	16,906	20,135
Total (boe per day) (6:1)	17,356	17,092	20,325	17,976	21,175
% Oil and NGL	84 %	84 %	84 %	84 %	84 %

Production

Surge averaged production of 17,356 boe per day in the fourth quarter of 2020 (84 percent oil and NGLs), a two percent increase compared to the average production rate in the third quarter of 2020 and a 15 percent decrease from the average production rate in the fourth quarter of 2019. The increase in production during the fourth quarter of 2020 as compared to the third quarter of 2020 is primarily due to the Company's successful fourth quarter drilling program.

During the year ended December 31, 2020, Surge achieved production of 17,976 boe per day (84 percent oil and NGLs), a 15 percent decrease when compared to the same period of 2019.

The decrease in production for the three months and year ended December 31, 2020 as compared to the same periods of the prior year is primarily the result of temporary production curtailments and natural production declines more than offsetting production additions from the Company's 2020 drilling program. In addition, the Company sold approximately 300 boe per day of production resulting from the disposition of non-core assets in Central Alberta and Northwest Alberta during the year ended December 31, 2020.

		Three Months Ended		Years Ended Dec 31,
($000s except per amount)	Dec 31, 2020	Sep 30, 2020	Dec 31, 2019	2020	2019
Petroleum and Natural GasRevenue
Oil	55,565	54,000	86,905	199,208	376,238
NGL	1,745	1,161	2,076	4,613	8,109
Oil and NGL	57,310	55,161	88,981	203,821	384,347
Natural gas	2,597	1,770	2,808	7,228	10,002
Total petroleum and natural gasrevenue	59,907	56,931	91,789	211,049	394,349
Realized Prices
Oil ($ per bbl)	43.80	42.66	57.46	37.39	60.19
NGL ($ per bbl)	26.14	21.68	35.84	21.00	32.09
Oil and NGL ($ per bbl)	42.92	41.81	56.66	36.74	59.09
Natural gas ($ per mcf)	1.66	1.17	1.56	1.17	1.36
Total petroleum and natural gasrevenue before realizedcommodity and FX contracts ($ perboe)	37.52	36.21	49.09	32.08	51.02
Benchmark Prices
WTI (US$ per bbl)	42.66	40.93	56.96	39.40	57.03
CAD/USD exchange rate	1.30	1.33	1.32	1.34	1.33
WTI (C$ per bbl)	55.46	54.44	75.19	52.80	75.85
Edmonton Light Sweet (C$ per bbl)	49.98	49.55	67.97	45.18	69.04
WCS (C$ per bbl)	43.42	42.40	54.30	35.59	58.78
AECO Daily Index (C$ per mcf)	2.64	2.24	2.48	2.23	1.76

Petroleum and Natural Gas Revenue, Realized Prices and Benchmark Pricing

Total petroleum and natural gas revenue for the fourth quarter of 2020 increased five percent as compared to the third quarter of 2020. The increase is primarily due to a two percent increase in production and an increase in average realized oil and natural gas prices during the period. This increase correlates to the four percent increase in WTI crude oil pricing and 18 percent increase in AECO natural gas pricing.

Total petroleum and natural gas revenue for the three months and year ended December 31, 2020 decreased 35 percent and 46 percent when compared to the same periods of 2019. The decrease is primarily due to a decrease in average realized oil prices, correlating to a decrease in crude oil benchmark pricing, along with a decrease in production during the periods.

ROYALTIES

		Three Months Ended		Years Ended Dec 31,
($000s except per boe)	Dec 31, 2020	Sep 30, 2020	Dec 31, 2019	2020	2019
Royalties	6,493	6,285	13,096	24,498	51,837
% of petroleum and natural gasrevenue	11 %	11 %	14 %	12 %	13 %
$ per boe	4.07	4.00	7.00	3.72	6.71

As royalties are sensitive to both commodity prices and production levels, the corporate royalty rates will fluctuate with commodity prices, well production rates, production decline of existing wells, and performance and geographic location of new wells drilled.

Royalties as a percentage of revenue for the fourth quarter of 2020 are comparable to the immediate preceding quarter.

Royalties as a percentage of revenue for the three months and year ended December 31, 2020 decreased as compared to the same periods of the prior year primarily as a result of lower crude oil pricing environment and production levels.

NET OPERATING EXPENSES

		Three Months Ended		Years Ended Dec 31,
($000s except per boe)	Dec 31, 2020	Sep 30, 2020	Dec 31, 2019	2020	2019
Operating expenses	26,531	23,204	29,448	101,640	116,338
Less processing income	(1,006)	(934)	(1,564)	(4,772)	(4,303)
Net operating expenses	25,525	22,270	27,884	96,868	112,035
$ per boe	15.99	14.16	14.91	14.72	14.50

Net operating expenses per boe and total net operating expenses for the fourth quarter of 2020 increased when compared to the immediate preceding quarter primarily attributable to an increase in maintenance work that was previously deferred until crude oil price stabilization began in the fourth quarter.

Net operating expenses per boe for the three months and year ended December 31, 2020 increased as compared to the same period of the prior year primarily due to a 15 percent decrease in production in addition to limited drilling activity in low operating cost areas during the year following the suspension of the Company's capital program in March 2020.

TRANSPORTATION EXPENSES

		Three Months Ended		Years Ended Dec 31,
($000s except per boe)	Dec 31, 2020	Sep 30, 2020	Dec 31, 2019	2020	2019
Transportation expenses	1,892	2,187	2,624	9,766	11,866
$ per boe	1.18	1.39	1.40	1.48	1.54

Transportation expenses per boe for the fourth quarter of 2020 decreased 15 percent when compared to the third quarter of 2020 primarily due to the termination of a firm transport commitment and a pipeline tie-in project in the Sparky area.

Transportation expenses per boe for the three months and year ended December 31, 2020 decreased as compared to the same period of the prior year as a result of the Company's continued focus of its drilling program in areas with existing pipeline infrastructure in addition to the termination of a firm transport commitment.

GENERAL AND ADMINISTRATIVE EXPENSES (G&A)

		Three Months Ended		Years Ended Dec 31,
($000s except per boe)	Dec 31, 2020	Sep 30, 2020	Dec 31, 2019	2020	2019
G&A expenses	4,132	3,430	4,805	16,105	19,445
Recoveries and capitalizedamounts	(1,164)	(430)	(1,165)	(3,619)	(5,158)
Net G&A expenses	2,968	3,000	3,640	12,486	14,287
Net G&A expenses $ per boe	1.86	1.91	1.95	1.90	1.85

Net G&A expenses per boe for the fourth quarter of 2020 decreased three percent when compared to the third quarter of 2020. The decrease in net G&A per boe is primarily attributable to higher recoveries and capitalized amounts resulting from increased capital activity in combination with higher production.

Net G&A expenses per boe for the three months and year ended December 31, 2020 decreased five percent and increased three percent, respectively, when compared to the same periods of the prior year.

Total net G&A expenses decreased as compared to the three months and year ended December 31, 2019 primarily due to receipt of $2.1 million from the Canada Emergency Wage Subsidy ("CEWS") for the year ended December 31, 2020 that was recorded to salaries and wages expense and the receipt of $0.1 million from the Canada Emergency Rent Subsidy ("CERS") in the fourth quarter of 2020 that was recorded to rent expense.

TRANSACTION AND OTHER COSTS

		Three Months Ended		Years Ended Dec 31,
($000s except per boe)	Dec 31, 2020	Sep 30, 2020	Dec 31, 2019	2020	2019
Transaction and other costs	—	—	(1,200)	98	173
$ per boe	—	—	(0.64)	0.01	0.02

The Company did not incur any transaction and other costs during the fourth quarter of 2020.

Transaction and other costs during the three months and year ended December 31, 2019 primarily related to an asset acquisition in Southeast Alberta during the third quarter of 2019, a non-core asset disposition in Northwest Alberta during the first quarter of 2019 and a disposal of a 1.7 percent gross overriding royalty ("GORR") at the end of the second quarter of 2019, in addition to severance costs. During the fourth quarter of 2019, the Company unwound an other long term obligation that resulted in a $1.3 million gain recognized in transaction and other costs.

FINANCE EXPENSES

	Three Months Ended				Years Ended Dec 31,
($000s except per boe)	Dec 31, 2020	Sep 30, 2020	Dec 31, 2019	2020	2019
Interest on bank debt	5,607	5,308	3,778	17,251	19,838
$ per boe	3.51	3.38	2.02	2.62	2.57
Interest on convertible debentures	1,222	1,222	1,206	4,888	4,052
$ per boe	0.77	0.78	0.64	0.74	0.52
Interest on lease and otherobligations	776	813	814	3,325	2,419
$ per boe	0.49	0.52	0.44	0.51	0.31
Realized loss on interest contracts	710	696	113	2,194	348
$ per boe	0.44	0.44	0.06	0.33	0.05
Total interest expense	8,315	8,039	5,911	27,658	26,657
$ per boe	5.21	5.11	3.16	4.20	3.45
Accretion expense	1,380	1,381	1,803	5,907	6,750
$ per boe	0.86	0.88	0.96	0.90	0.87
Unrealized loss (gain) on interestcontracts	(570)	(471)	(1,608)	4,993	1,556
$ per boe	(0.36)	(0.30)	(0.86)	0.76	0.20
Paid in kind interest on term debt	218	—	—	218	—
$ per boe	0.14	—	—	0.03	—
Total finance expense	9,342	8,949	6,106	38,776	34,963
$ per boe	5.85	5.69	3.27	5.89	4.52

Total interest expense for the fourth quarter of 2020 increased when compared to the immediate preceding quarter and same period of 2019, primarily due to higher average interest rates on bank debt and higher realized loss on interest contracts during the periods.

The increase in interest expense for the year ended December 31, 2020 as compared to the same period of 2019 is due to an increase in realized loss on interest contracts, interest on convertible debentures and interest on lease and other obligations, offset by lower average bank debt during the period.

Total finance expense includes accretion, representing the change in the time value of the decommissioning liability and convertible debentures as well as unrealized gains and losses on financial interest contracts and paid in kind interest on term debt. Accretion expense for the fourth quarter of 2020 was comparable to the third quarter of 2020 and accretion expense for the three months and year ended December 31, 2020 decreased as compared to the same period of 2019, primarily due to a reduction in the discount rate during the periods. Unrealized gains on financial interest contracts for the three months ended December 31, 2020 increased compared to the immediate preceding quarter due to a decrease in floating interest rates and the semi-annual step up over the period. Unrealized loss on financial interest contracts for the year ended December 31, 2020 increased when compared to the same period of 2019 due to higher notional amounts hedged in combination with a decrease in floating interest rates and the semi-annual step up over the period.

NETBACKS

	Three Months Ended				Years Ended Dec 31,
($ per boe, except production)	Dec 31, 2020	Sep 30, 2020	Dec 31, 2019	2020	2019
Average production (boe per day)	17,356	17,092	20,325	17,976	21,175
Petroleum and natural gas revenue	37.52	36.21	49.09	32.08	51.02
Realized gain (loss) on commodityand FX contracts	(3.91)	(1.67)	0.13	3.05	(0.61)
Royalties	(4.07)	(4.00)	(7.00)	(3.72)	(6.71)
Net operating expenses	(15.99)	(14.16)	(14.91)	(14.72)	(14.50)
Transportation expenses	(1.18)	(1.39)	(1.40)	(1.48)	(1.54)
Operating netback	12.37	14.99	25.91	15.21	27.66
G&A expense	(1.86)	(1.91)	(1.95)	(1.90)	(1.85)
Interest expense	(5.21)	(5.11)	(3.16)	(4.20)	(3.45)
Adjusted funds flow	5.30	7.97	20.80	9.11	22.36

Please refer to the respective sections of the MD&A for a detailed explanation of the changes to the netback as compared to prior periods.

STOCK-BASED COMPENSATION

		Three Months Ended	Years Ended Dec 31,
($000s except per boe)	Dec 31, 2020	Sep 30, 2020	Dec 31, 2019	2020	2019
Stock-based compensation	1,233	1,797	1,749	6,894	10,582
Capitalized stock-basedcompensation	(413)	—	(678)	(1,170)	(4,303)
Net stock-based compensation	820	1,797	1,071	5,724	6,279
Net stock-based compensation$ per boe	0.51	1.14	0.57	0.87	0.81

Net stock-based compensation expense for the fourth quarter of 2020 decreased as compared to the immediate preceding quarter and to the three months and year ended December 31, 2019. The decrease in net stock-based compensation is primarily the result of an increase of forfeited awards during the periods. Capitalized stock-based compensation was recorded for the current quarter as the capital program resumed.

The stock-based compensation recorded in the year ended December 31, 2020 relates to the restricted share awards ("RSAs") and performance share awards ("PSAs") grants. Subject to terms and conditions of the plan, each RSA entitles the holder to an award value not limited to, but typically paid as to one-third on each of the first, second and third anniversaries of the date of grant. Each PSA entitles the holder to an award value to be typically paid on the third anniversary of the date of grant. For the purpose of calculating share-based compensation, the fair value of each award is determined at the grant date using the closing price of the common shares. A weighted average forfeiture rate of 8% (2019 - 7%) for PSAs and 6% (2019 - 8%) for RSAs was used to value all awards granted for the year ended December 31, 2020. The weighted average fair value of awards granted for the year ended December 31, 2020 is $0.33 (2019 - $1.04) per PSA and $0.33 (2019 - $1.05) per RSA. In the case of PSAs, the award value is adjusted for a payout multiplier which can range from 0.0 to 2.0 and is dependent on the performance of the Company relative to pre-defined corporate performance measures for a particular period.

The number of restricted and performance share awards outstanding are as follows:

	Number of restrictedshare awards	Number of performanceshare awards
Balance at December 31, 2019	5,775,594	7,602,333
Granted	7,316,630	6,538,409
Reinvested (1)	242,971	320,027
Exercised	(2,669,765)	(2,046,058)
Forfeited	(677,796)	(487,363)
Balance at December 31, 2020	9,987,634	11,927,348

(1) Per the terms of the plan, cash dividends paid by the Company are reinvested to purchase incremental awards.

DEPLETION AND DEPRECIATION

		Three Months Ended		Years Ended Dec 31,
($000s except per boe)	Dec 31, 2020	Sep 30, 2020	Dec 31, 2019	2020	2019
Depletion and depreciation expense	24,578	22,250	39,763	105,042	163,450
$ per boe	15.39	14.15	21.27	15.97	21.15

Depletion and depreciation are calculated based on total capital expenditures (including acquisitions and dispositions), production rates and proved and probable oil and gas reserves. Deducted from the Company's fourth quarter of 2020 depletion and depreciation calculation are costs associated with salvage values of $59.6 million. Future development costs for proved and probable oil and gas reserves of $839.4 million have been included in the depletion calculation.

Depletion and depreciation expense for the three months ended December 31, 2020 increased compared to the immediate preceding quarter due to a decrease in depletable reserves as a result of the 2020 reserve evaluation and decreased compared to the same period of 2019 primarily due to a reduction of the depletable base as a result of the first quarter of 2020 and fourth quarter of 2019 impairment charge.

IMPAIRMENT

	Three Months Ended				Years Ended Dec 31,
($000s except per boe)	Dec 31, 2020	Sep 30, 2020	Dec 31, 2019	2020	2019
Impairment	37,425	—	180,701	628,053	180,701
$ per boe	23.44	—	96.64	95.46	23.38

The Company identified six cash generating units as of December 31, 2020 based on the lowest level at which properties generate cash inflows while applying judgment to consider factors such as shared infrastructure, geographic proximity, petroleum type and similar exposures to market risk and materiality. The Company's CGUs at December 31, 2020, which are unchanged from December 31, 2019, were geographically labeled Northwest Alberta, North Central Alberta, Northeast Alberta, Central Alberta, Southeast Alberta and Southwest Saskatchewan.

For the year ended December 31, 2020, the Company recognized an impairment charge of $628.1 million (year ended December 31, 2019 - $180.7 million), consisting of $590.6 million for the three month period ended March 31, 2020 due to declines in forecasted oil and natural gas commodity prices, and $37.5 million for the three month period ended December 31, 2020 due to economic performance of certain assets.

For the period ended December 31, 2020, due to poor economic performance of certain assets and the significant decrease in cash flows from proved and probable oil and gas reserves, the Company identified an indicator of potential impairment was present in its Southwest Saskatchewan CGU. As a result, the Company completed an impairment test. Recoverable value was estimated at value in use based on before tax discounted cash flows from proved and probable oil and gas reserves as at December 31, 2020. It was determined that the carrying value of the Southwest Saskatchewan CGU exceeded the recoverable amount of $43.1 million and a $37.5 million impairment charge was recognized. The before tax discount rate applied in the value in use calculation as at December 31, 2020 was 20 percent.

For the period ended December 31, 2020, the Company identified a trigger for potential reversal of historical impairment at its Northeast Alberta and Southeast Alberta CGU's. As a result, the Company completed an impairment reversal test and determined that the fair values approximated the carrying values of the Northeast Alberta and Southeast Alberta CGU's so no reversal of historical impairment was recorded. The Company determined that there were no aggregate indicators of impairment or historical impairment reversal at December 31, 2020 for the Northwest Alberta, North Central Alberta and Central Alberta CGUs and no impairment tests were required.

For the period ended March 31, 2020, due to declines in forecasted oil and natural gas commodity prices, the Company identified an indicator of impairment was present in all of its six CGUs. As a result, the Company completed an impairment test. Recoverable value was estimated at value in use based on before tax discounted cash flows from oil and gas proved and probable oil and gas reserves as at December 31, 2019, which were updated by the internal reserve evaluators to March 31, 2020. It was determined that the carrying value of the Northwest Alberta CGU exceeded the recoverable amount of $139.5 million, the carrying value of the North Central Alberta CGU exceeded the recoverable amount of $124.4 million, the carrying value of the Northeast Alberta CGU exceeded the recoverable amount of $31.3 million, the carrying value of the Central Alberta CGU exceeded the recoverable amount of $5.2 million, the carrying value of the Southeast Alberta CGU exceeded the recoverable amount of $303.0 million, and the carrying value of the Southwest Saskatchewan CGU exceeded the recoverable amount of $100.0 million and a $590.6 million impairment charge was recognized. The before tax discount rate applied in the value in use calculation as at March 31, 2020 was 13 - 25 percent.

NET LOSS

		Three Months Ended	Years Ended Dec 31,
($000s except per share)	Dec 31, 2020	Sep 30, 2020	Dec 31, 2019	2020	2019
Net loss	(57,727)	(13,184)	(143,801)	(747,297)	(158,664)
Per share - basic ($)	(0.17)	(0.04)	(0.44)	(2.22)	(0.50)
Per share - diluted ($)	(0.17)	(0.04)	(0.44)	(2.22)	(0.50)

The Company realized net loss and net loss per basic share for the fourth quarter of 2020. The higher net loss as compared to the immediate preceding quarter is primarily due to the recognition of an impairment charge in the fourth quarter of 2020.

The Company realized a higher net loss and net loss per basic share for the year ended December 31, 2020 as compared to the same period of 2019. The loss is primarily due to the recognition of an impairment charge, an unrealized loss on financial contracts, along with a decrease in average realized price per barrel of oil during the year.

INCOME TAXES

The estimated tax pools in place at December 31, 2020 are as follows:

($000s)	Total
Canadian oil and gas property expenses	341,894
Canadian development expenses	140,569
Canadian exploration expenses	24,784
Undepreciated capital cost	102,416
Non-capital losses	502,435
Other	2,215
	1,114,313

CAPITAL EXPENDITURES

Capital Expenditure Summary

($000s)	Q1 2020	Q2 2020	Q3 2020	Q4 2020	2020 YTD	2019 YTD	% Change
Land	376	90	99	107	672	6,795	(90) %
Seismic	260	—	—	—	260	1,275	(80) %
Drilling and completions	22,411	—	423	10,346	33,180	80,464	(59) %
Facilities, equipment and pipelines	7,902	2,984	1,520	2,099	14,505	24,893	(42) %
Other	1,555	442	435	1,724	4,156	6,038	(31) %
Total exploration and development	32,504	3,516	2,477	14,276	52,773	119,465	(56) %
Acquisitions - cash consideration	—	—	—	—	—	14,808	(100) %
Property dispositions	—	(5,276)	(762)	—	(6,038)	(57,246)	(89) %
Total acquisitions & dispositions	—	(5,276)	(762)	—	(6,038)	(42,438)	(86) %
Total capital expenditures	32,504	(1,760)	1,715	14,276	46,735	77,027	(39) %

During the three months and year ended December 31, 2020, Surge invested a total of $14.3 million and $52.8 million, excluding acquisitions and dispositions.

During the fourth quarter of 2020, Surge invested $10.3 million on the drilling program in the Sparky area, $1.9 million on facility maintenance and pipeline tie-in at Sparky, and $0.2 million optimizing producing wellbores and facility maintenance at Valhalla and Shaunavon. An additional $1.8 million was spent on land and other capital items during the quarter.

During the year ended December 31, 2020, the Company disposed of certain non-core assets in Central Alberta for cash proceeds of $0.8 million and disposed of certain non-core assets in Northwest Alberta for cash proceeds of $5.3 million.

Due to the COVID-19 outbreak and decreases in global commodity prices, Surge has suspended its previously announced 2020 guidance and capital program of $98.5 million. In November 2020, Surge announced that it had secured a $40.0 million Term Facility under the BDC's BCAP Mid-Market Financing Program to fund a capital program to return production to near pre-COVID-19 levels.

FACTORS THAT HAVE CAUSED VARIATIONS OVER THE QUARTERS

The fluctuations in Surge's revenue and net earnings from quarter to quarter are primarily caused by changes in production volumes, changes in realized commodity prices and the related impact on royalties, realized and unrealized gains or losses on derivative instruments, and changes in impairment charges and non-cash items. The change in production from the first quarter of 2019 through the current quarter is due to Surge's drilling programs and acquisitions and dispositions over that period. Please refer to the Financial and Operating Results section and other sections of this MD&A for detailed discussions on variations during the comparative quarters and to Surge's previously issued interim and annual MD&A for changes in prior quarters.

Share Capital and Option Activity

	Q4 2020	Q3 2020	Q2 2020	Q1 2020
Weighted common shares	339,784,739	337,115,352	335,068,916	332,187,964
Dilutive instruments (treasury method)	—	—	—	—
Weighted average diluted shares outstanding	339,784,739	337,115,352	335,068,916	332,187,964
	Q4 2019	Q3 2019	Q2 2019	Q1 2019
Weighted common shares	324,835,793	318,075,528	314,010,237	309,447,717
Dilutive instruments (treasury method)	—	—	—	—

On March 9, 2021, Surge had 339,784,739 common shares, 11,839,380 PSAs, and 9,749,926 RSAs outstanding.

Quarterly Financial Information

	Q4 2020	Q3 2020	Q2 2020	Q1 2020
Oil, Natural gas & NGL sales	59,907	56,931	30,505	63,706
Net loss	(57,727)	(13,184)		(61,159) (615,227)
Net loss per share ($):
Basic	(0.17)	(0.04)	(0.18)	(1.85)
Diluted	(0.17)	(0.04)	(0.18)	(1.85)
Cash flow from operating activities	11,000	15,082	2,970	43,138
Cash flow from operating activities per share ($):
Basic	0.03	0.04	0.01	0.13
Diluted	0.03	0.04	0.01	0.13
Adjusted funds flow	8,467	12,523	8,854	30,028
Adjusted funds flow per share ($):
Basic	0.02	0.04	0.03	0.09
Diluted	0.02	0.04	0.03	0.09
Average daily sales
Oil (bbls/d)	13,788	13,759	13,813	16,891
NGL (bbls/d)	726	582	528	564
Natural gas (mcf/d)	17,050	16,503	16,664	17,409
Barrels of oil equivalent (boe per day) (6:1)	17,356	17,092	17,118	20,357
Average sales price
Natural gas ($/mcf)	1.66	1.17	0.94	0.90
Oil ($/bbl)	43.80	42.66	22.62	39.82
NGL ($/bbl)	26.14	21.68	13.41	20.72
Barrels of oil equivalent ($/boe)	37.52	36.21	19.58	34.39

Quarterly Financial Information

	Q4 2019	Q3 2019	Q2 2019	Q1 2019
Oil, Natural gas & NGL sales	91,789	97,026	107,665	97,868
Net loss	(143,801)	(4,269)	(2,611)	(7,983)
Net loss per share ($):
Basic	(0.44)	(0.01)	(0.01)	(0.03)
Diluted	(0.44)	(0.01)	(0.01)	(0.03)
Cash flow from operating activities	34,474	40,228	45,807	28,908
Cash flow from operating activities per share ($):
Basic	0.11	0.13	0.15	0.09
Diluted	0.11	0.13	0.15	0.09
Adjusted funds flow	38,881	41,513	50,742	41,851
Adjusted funds flow per share ($):
Basic	0.12	0.13	0.16	0.14
Diluted	0.12	0.13	0.16	0.14
Average daily sales
Oil (bbls/d)	16,441	17,170	17,366	17,542
NGL (bbls/d)	630	769	727	644
Natural gas (mcf/d)	19,521	19,668	20,706	20,663
Barrels of oil equivalent (boe per day) (6:1)	20,325	21,217	21,544	21,630
Average sales price
Natural gas ($/mcf)	1.56	0.69	0.86	2.32
Oil ($/bbl)	57.46	59.39	66.05	57.72
NGL ($/bbl)	35.84	27.69	24.93	41.86
Barrels of oil equivalent ($/boe)	49.09	49.71	54.92	50.27

Annual Financial Information

	Years Ended December 31,
($000s except per share)	2020	2019	2018
Total petroleum and natural gas revenue	211,049	394,349	304,547
Net loss	(747,297)	(158,664)	(71,533)
Net loss per share ($):
Basic	(2.22)	(0.50)	(0.29)
Diluted	(2.22)	(0.50)	(0.29)
Total assets	707,964	1,425,854	1,566,708
Total long-term financial liabilities	135,895	423,684	446,566
Dividends declared	5,863	31,776	24,637
Dividends declared per share ($):
Basic	0.02	0.10	0.10
Diluted	0.02	0.10	0.10

LIQUIDITY AND CAPITAL RESOURCES

On December 31, 2020, Surge had $260.9 million drawn on its credit facility, $32.5 million drawn on its term facility, $79.0 million principal amount of convertible subordinated unsecured debentures ("Debentures"), and total net debt of $381.0 million, a comparable total net debt to the same date in 2019. At December 31, 2020, Surge had approximately $74.1 million of borrowing capacity in relation to the $335 million credit facility. The following tables set forth the consolidated capitalization of Surge and the change in the components of the Debentures:

Consolidated Capitalization

($000s)	Outstanding as atDecember 31, 2020
Shareholder Equity
Share capital	1,482,249
Common shares outstanding	339,785
Debentures - equity	6,266
Debt
Credit Facilities
Total Commitment	335,000
Amount drawn	260,908
Term Facility
Total Commitment	40,000
Amount drawn	32,500
Debentures - liability	71,181

Convertible Debentures

	Number of convertibledebentures	Liability Component($000s)	Equity Component($000s)
Balance at December 31, 2018	44,500	37,973	3,551
Issuance of convertible debentures	34,500	30,551	3,949
Issue costs	—	(1,776)	(230)
Deferred income tax liability	—	—	(1,004)
Accretion of discount	—	1,951	—
Balance at December 31, 2019	79,000	68,699	6,266
Accretion of discount	—	2,482	—
Balance at December 31, 2020	79,000	71,181	6,266

Surge monitors its capital structure and makes adjustments according to market conditions in an effort to meet its objectives. Currently, Surge anticipates that the future capital requirements will be funded through a combination of internal cash flow, divestitures, and debt and/or equity financing. There can be no guarantees that the credit facility will be extended or that alternative forms of debt and equity financing will be available on terms acceptable to the Company to meet its capital requirements.

During the year ended December 31, 2020, approximately $4.9 million was granted to Surge through the Alberta Site Rehabilitation Program ("SRP") to pay service companies to complete abandonment and reclamation work.

Due to decreases in crude oil prices, effective March 2020, the dividend was decreased to $0.000833 per share per month. Due to a further decrease in crude oil prices, effective April 2020, the dividend was suspended until such time as Surge's management and Board see a sustainable recovery in world crude oil prices.

Net Debt
($000s)	As at December 31, 2020
Bank debt	(260,908)
Term debt	(32,718)
Accounts receivable	29,796
Prepaid expenses and deposits	5,253
Accounts payable and accrued liabilities	(51,265)
Convertible debentures	(71,181)
Total	(381,023)

Bank Debt

As at December 31, 2020, the Company had a total commitment of $335.0 million, being the aggregate of a committed revolving term facility of $155.0 million, a committed non-revolving term facility of $167.5 million, and an operating loan facility of $12.5 million, with a syndicate of banks. The revolving term commitment will continue to revolve until the next scheduled borrowing base redetermination date of June 30, 2021. The further extension of the credit facility is dependent on the Company's ability to repay or extend the term of the $167.5 million committed non-revolving term facility that matures and requires repayment on December 31, 2021. As the available lending limits of the facilities are based on the syndicate's interpretation of the Company's reserves, commodity prices and decommissioning obligations, there can be no assurance that the amount of the available facilities will not decrease at the next scheduled review. In the current pricing environment, there is an increased risk that the lenders may decrease the amount available under the credit facility and the decreases could be material. Interest rates vary depending on the ratio of Senior Debt to EBITDA (as defined in the lending agreement). As at December 31, 2020, the Company had an effective interest rate of prime plus 4.50 percent on the revolving term facility (December 31, 2019 – prime plus 1.25 percent on a $350 million revolving term/operating loan facility) and an effective interest rate of prime plus 7.50 percent on the non-revolving term facility (December 31, 2019 - not applicable).

The facility is secured by a general assignment of book debts, debentures of $1.5 billion with a floating charge over all assets of the Company with a negative pledge and undertaking to provide fixed charges on the major producing petroleum and natural gas properties at the request of the bank.

The financial covenant, whereby the Company's ratio of Net Senior Debt to EBITDA shall not exceed 3.00:1.00, was removed effective June 19, 2020.

Term Debt

As at December 31, 2020, the Company had a term loan commitment with Business Development Bank of Canada, for a four year, non-revolving second lien term facility of $40 million, maturing on November 17, 2024. At December 31, 2020, the Company had $32.5 million drawn on its term facility with $7.5 million of available borrowing capacity. Interest on the outstanding term loan will accrue and be added to the principal amount (capitalized) in the first year. Interest on the outstanding term loan will be due and payable monthly by the Company thereafter. Interest on borrowings are summarized as follows:

• i. for the period between November 17, 2020 and the first anniversary date, at a per annum rate equal to 5.0 percent;
• ii. thereafter until the second anniversary date, at a per annum rate equal to the greater of: the senior interest rate plus 1.0 percent; and 6.0 percent;
• iii. thereafter until the third anniversary date, at a per annum rate equal to the greater of: the senior interest rate plus 2.0 percent; and 7.0 percent;
• iv. thereafter, at a per annum rate equal to the greater of: the senior interest rate plus 3.0 percent; and 8.0 percent.

As at December 31, 2020, the Company had an effective interest rate of 5.0 percent on the non-revolving term facility (December 31, 2019 - not applicable).

As at December 31, 2020, the Company was compliant with all restrictions in its first and second lien credit agreements.

RELATED-PARTY AND OFF-BALANCE-SHEET TRANSACTIONS

Surge was not involved in any off-balance-sheet transactions or related party transactions during the year ended December 31, 2020.

CONTRACTUAL OBLIGATIONS

The Company is contractually obligated under its debt agreements as outlined under liquidity and capital resources.

As at December 31, 2020, Surge had future minimum payments relating to its variable office rent payments and firm transport commitments totaling $24.9 million, as summarized below:

	December 31,2020
Less than 1 year	$9,861
1 - 3 years	7,081
3 - 5 years	4,842
5+ years	3,109
Total commitments	$24,893

During the year ended December 31, 2019, the Company sold a 1.7 percent gross overriding royalty ("GORR") on the total revenue from the Company's Southwest Saskatchewan, Southeast Alberta and North Central Alberta assets, effective May 1, 2019. The Company has a drilling commitment on the GORR lands that must be fulfilled by April 30, 2022. In the event that the Company fails to fulfill the drilling commitment, the GORR shall increase from 1.7 percent to 2.7 percent. For the year ended December 31, 2020, Surge has drilled 53 out of the 100 wells that are required to meet the drilling commitment.

LEASES

The Company has recognized the following lease and other obligations:

	Total
Lease obligations at December 31, 2018	$5,871
Additions upon adoption of IFRS 16 at January 1, 2019	29,886
Lease modifications	5,643
Interest expense	2,100
Payments	(8,910)
Other obligations	12,094
Lease and other obligations at December 31, 2019	$46,684
Additions	2,209
Interest expense	3,325
Payments	(11,425)
Lease and other obligations at December 31, 2020	$40,792
Current portion	8,796
Long term portion	31,996

Future minimum payments relating to lease and other obligations at December 31, 2020 are as follows:

	December 31,2020
Less than 1 year	$11,658
1 - 3 years	20,848
3 - 5 years	15,372
5+ years	1,875
Lease and other obligation payments	$49,753

FINANCIAL INSTRUMENTS

As a means of managing commodity price, interest rate, and foreign exchange volatility, the Company enters into various derivative financial instrument agreements and physical contracts. The fair value of forward contracts and swaps is determined by discounting the difference between the contracted prices and published forward price curves as at the statement of financial position date, using the remaining contracted oil and natural gas volumes and a risk-free interest rate (based on published government rates). The fair value of options and costless collars is based on option models that use published information with respect to volatility, prices and interest rates. Surge's financial derivative contracts are classified as level two.

The following table summarizes the Company's financial derivatives as at March 9, 2021 by period and by product.

Commodity Contracts

West Texas Intermediate Crude Oil Derivative Contracts (WTI)

	Swaps		Collars			Three-way Collar
Period	Volumes(bbls/d)	AveragePrice(CAD/bbl)	Volumes(bbls/d)	AverageBought Put(CAD/bbl)	Average SoldCall(CAD/bbl)	Volumes(bbls/d)	Average SoldPut(CAD/bbl)	AverageBought Put(CAD/bbl)	Average SoldCall(CAD/bbl)
Qtr. 1 2021	5,550	$52.25	200	$53.00	$63.30	2,000	$40.41	$51.86	$60.96
Qtr. 2 2021	6,167	$53.40	950	$53.53	$60.41	500	$39.45	$49.64	$64.91
Qtr. 3 2021	4,684	$55.03	1,700	$53.59	$61.55	250	$44.54	$54.73	$64.91
Qtr. 4 2021	4,534	$55.33	1,450	$53.34	$61.64	250	$44.54	$54.73	$64.91
Qtr. 1 2022	1,000	$59.11	2,000	$55.00	$69.23

Western Canadian Select Derivative Contracts (WCS)

	Swaps
Period	Volumes(bbls/d)	Average Price(CAD/bbl)
Qtr. 1 2021	6,000	$(17.69)
Qtr. 2 2021	6,000	$(17.69)
Qtr. 3 2021	5,000	$(17.36)
Qtr. 4 2021	1,500	$(17.05)

Mixed Sweet Blend Derivative Contracts (MSW)

	Swaps
Period	Volumes(bbls/d)	Average Price(CAD/bbl)
Qtr. 1 2021	2,000	$(6.81)
Qtr. 2 2021	2,000	$(6.81)
Qtr. 3 2021	2,250	$(6.64)
Qtr. 4 2021	1,500	$(6.62)

Natural Gas Derivative Contracts

	Chicago Swaps		Chicago Collars			AECO Swaps
Period	Volumes(MMBtu/d)	Average Price(CAD/MMBtu)	Volumes(MMBtu/d)	Average BoughtPut(CAD/MMBtu)	Average Sold Call(CAD/MMBtu)	Volumes(GJ/d)	Average Price(CAD/GJ)
Qtr. 1 2021	3,000	$3.21	3,000	$2.74	$3.69	6,000	$2.37
Qtr. 2 2021	3,000	$3.21	3,000	$2.74	$3.69	4,000	$2.40
Qtr. 3 2021	3,000	$3.21	3,000	$2.74	$3.69	2,000	$2.12
Qtr. 4 2021	1,011	$3.21	1,011	$2.74	$3.69	3,326	$2.40
Qtr. 1 2022						2,000	$2.83

Interest Rate Hedges

Type	Term	NotionalAmount (CAD$)	Surge Receives	Surge Pays	Fixed Rate SGY Pays
Fixed-to-Floating RateSwap	Feb 2018 - Feb 2023	$100,000,000	Floating Rate	Fixed Rate	Semi-Annual Step Up•Beginning at 1.786%•Ending at 2.714%•Averaging 2.479%
Fixed-to-Floating RateSwap	Jul 2019 - Jun 2024	$50,000,000	Floating Rate	Fixed Rate	1.7850%

SUBSEQUENT EVENTS

Subsequent to December 31, 2020, the Company executed a binding purchase and sale agreement for the disposition of certain core assets in Northeast Alberta and Southeast Alberta for cash proceeds of $106 million, subject to standard closing adjustments (the "Sale"). The Sale is set to close on or before March 25, 2021.

In combination with the Sale, the Company has reached an agreement in principle with its respective lender syndicates to re-determine its first and second lien credit facilities. At the closing of the Sale, Surge anticipates the first lien credit facilities will be re-determined at $215 million, with the Company's next bank review scheduled on or before November 30, 2021. The Company's total commitment of $215.0 million, will be the aggregate of a committed revolving term facility of $120.0 million, a committed non-revolving term facility of $75.0 million, and an operating loan facility of $20.0 million.

Subsequent to December 31, 2020, the Company borrowed the remaining $7.5 million available on its $40 million BDC term loan.

CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Disclosure controls and procedures ("DC&P"), as defined in National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings, are designed to provide reasonable assurance that information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in the securities legislation and include controls and procedures designed to ensure that information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted under securities legislation is accumulated and communicated to the Company's management, including its certifying officers, as appropriate to allow timely decisions regarding required disclosure.

There were no changes in the Company's DC&P during the year ended December 31, 2020 that materially affected, or are reasonably likely to materially affect, the Company's DC&P.

Internal Controls over Financial Reporting

Internal control over financial reporting ("ICFR"), as defined in National Instrument 52-109, includes those policies and procedures that:

1. pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets of the Company;

2. are designed to provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the Company are being made in accordance with authorizations of management and Directors of Surge; and

3. are designed to provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company's assets that could have a material effect on the financial statements.

The Chief Executive Officer and Chief Financial Officer are responsible for designing internal controls over financial reporting or causing them to be designed under their supervision in order to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. The Company's Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, disclosure controls and procedures to provide reasonable assurance that: (i) material information relating to the Company is made known to the Company's Chief Executive Officer and Chief Financial Officer by others, particularly during the period in which the annual filings are being prepared; and (ii) information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time period specified in securities legislation.

The Committee of Sponsoring Organizations of the Treadway Commission ("COSO") 2013 framework provides the basis for management's design of internal controls over financial reporting. Management and the Board work to mitigate the risk of a material misstatement in financial reporting; however, a control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met and it should not be expected that the disclosure and internal control procedures will prevent all errors or fraud.

There were no changes in the Company's ICFR during the year ended December 31, 2020 that materially affected, or are reasonably likely to materially affect, the Company's ICFR.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with IFRS requires management to make certain judgments and estimates. Due to the timing of when activities occur compared to the reporting of those activities, management must estimate and accrue operating results and capital spending. Changes in these judgments and estimates could have a material impact on our financial results and financial condition.

Reserves

Estimation of recoverable quantities of proved and probable reserves include estimates and assumptions regarding forecasted oil and gas commodity prices, exchange rates, discount rates, forecasted production, forecasted operating costs, royalty costs and future development costs for future cash flows as well as the interpretation of complex geological and geophysical models and data. Changes in reported reserves can affect the impairment of assets, the decommissioning obligations, the economic feasibility of exploration and evaluation assets and the amounts reported for depletion, depreciation and amortization of property, plant and equipment. These reserve estimates are undertaken by independent third party reserve evaluators, who work with information provided by the Company to establish reserve determinations in accordance with National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities.

Forecasted Oil and Gas Commodity Prices

Management's estimates of forecasted oil and gas commodity prices are critical as these prices are used to determine the carrying amount of PP&E, assess impairment and determine the change in fair value of financial contracts. Management's estimates of prices are based on the price forecast from our independent third party reserve evaluators and the current forward market.

Business Combinations

Management makes various assumptions in determining the fair values of any acquired company's assets and liabilities in a business combination. The most significant assumptions and judgments made relate to the estimation of the fair value of the oil and gas properties. To determine the fair value of these properties, we estimate (a) proved and probable oil and gas reserves in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities and (b) forecasted oil and gas commodity prices.

Decommissioning Liability

Management calculates the decommissioning liability based on estimated costs to abandon and reclaim its net ownership interest in all wells and facilities and the estimated timing of the costs to be incurred in future periods. The fair value estimate is capitalized to PP&E as part of the cost of the related asset and amortized over its useful life. There are uncertainties related to decommissioning liabilities and the impact on the financial statements could be material as the eventual timing and costs for the obligations could differ from our estimates. Factors that could cause our estimates to differ include any changes to laws or regulations, reserve estimates, costs and technology.

Derivative Financial Instruments

Surge utilizes derivative financial instruments to manage its exposure to market risks relating to commodity prices, foreign currency exchange rates and interest rates. Fair values of derivative contracts fluctuate depending on the underlying estimate of future commodity prices, foreign currency exchange rates, interest rates and counterparty credit risk.

Stock-based Compensation

Management makes various assumptions in determining the value of stock based compensation. This includes estimating the forfeiture rate, the expected volatility of the underlying security, interest rates and expected life.

Deferred Income Taxes

Management makes various assumptions in determining the deferred income tax provision, including (but not limited to) future tax rates, accessibility of tax pools and future cash flows.

Leases

The preparation of the consolidated financial statements in accordance with IFRS requires management to make judgments, estimates, and assumptions that affect the reported amount of assets, liabilities, income, and expenses. Actual results could differ significantly from these estimates. Key areas where management has made judgments, estimates, and assumptions related to the application of IFRS 16 include:

• Incremental borrowing rate: The Incremental borrowing rates are based on judgments including economic environment, term, currency, and the underlying risk inherent to the asset. The carrying balance of the right-of-use assets, lease obligations, and the resulting interest and depreciation expense, may differ due to changes in the market conditions and lease term.
• Lease term: Lease terms are based on assumptions regarding extension terms that allow for operational flexibility and future market conditions.

RISK FACTORS

Additional risk factors can be found under "Matters Relating to the COVID-19 Pandemic" in this MD&A or under "Risk Factors" in the Company's AIF for the year ended December 31, 2020, which can be found on www.sedar.com. Many risks are discussed below and in the AIF, but these risk factors should not be construed as exhaustive. There are numerous factors, both known and unknown, that could cause actual results or events to differ materially from forecast results.

Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome. The long-term commercial success of Surge depends on its ability to find, acquire, develop, and commercially produce oil and natural gas reserves. Without the continual addition of new reserves, any existing reserves Surge may have at any particular time and the production therefrom will decline over time as such existing reserves are exploited. A future increase in Surge's reserves will depend not only on the Company's ability to explore and develop any properties it may have from time to time, but also on its ability to select and acquire suitable producing properties or prospects. No assurance can be given that further commercial quantities of oil and natural gas will be discovered or acquired by Surge.

Surge's principal risks include finding and developing economic hydrocarbon reserves efficiently and being able to fund the capital program. The Company's need for capital is both short-term and long-term in nature. Short-term working capital will be required to finance accounts receivable, drilling deposits and other similar short-term assets, while the acquisition and development of oil and natural gas properties requires large amounts of long-term capital. Surge anticipates that future capital requirements will be funded through a combination of internal adjusted funds flow, debt and/or equity financing. There is no assurance that debt and equity financing will be available on terms acceptable to the Company to meet its capital requirements. If any components of the Company's business plan are missing, the Company may not be able to execute the entire business plan.

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial, and local laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and natural gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil, or water may give rise to liabilities to governments and third parties and may require Surge's operating entities to incur costs to remedy such discharge. Although Surge believes that it is in material compliance with current applicable environmental regulations, no assurance can be given that environment laws will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise adversely affect Surge's financial condition, results of operations or prospects.

Surge's involvement in the exploration for and development of oil and natural gas properties may result in Surge becoming subject to liability for pollution, blowouts, property damage, personal injury or other hazards. Although, prior to drilling, Surge will obtain insurance in accordance with industry standards to address certain of these risks, such insurance has limitations on liability that may not be sufficient to cover the full extent of such liability. In addition, such risks may not, in all circumstances, be insurable or, in certain circumstances, Surge may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. The payment of such uninsured liabilities would reduce the funds available to Surge. The occurrence of a significant event that was not fully insured against, or the insolvency of the insurer of such event, could have a material adverse effect on Surge's financial position, results of operations or prospects and will reduce income otherwise used to fund operations.

The Company's financial performance and condition are substantially dependent on the prevailing prices of oil and natural gas which are unstable and subject to fluctuation. Fluctuations in oil or natural gas prices could have an adverse effect on the Company's operations and financial condition and the value and amount of its reserves. Prices for crude oil fluctuate in response to global supply of and demand for oil, market performance and uncertainty and a variety of other factors which are outside the control of the Company including, but not limited, to the world economy and the Organization of the Petroleum Exporting Countries' ability to adjust supply to world demand, government regulation, political stability and the availability of alternative fuel sources. Natural gas prices are influenced primarily by factors within North America, including North American supply and demand, economic performance, weather conditions and availability and pricing of alternative fuel sources.

Decreases in oil and natural gas prices typically result in a reduction of the Company's net production revenue and may change the economics of producing from some wells, which could result in a reduction in the volume of the Company's reserves. Any further substantial declines in the prices of crude oil or natural gas could also result in delay or cancellation of existing or future drilling, development or construction programs or the curtailment of production. All of these factors could result in a material decrease in the Company's net production revenue, cash flows and profitability causing a reduction in its oil and gas acquisition and development activities. In addition, bank borrowings available to the Company will in part be determined by the Company's borrowing base. A sustained material decline in prices from historical average prices could further reduce such borrowing base, therefore reducing the bank credit available and could require that a portion of its bank debt be repaid.

The Company utilizes financial derivatives contracts to manage market risk. All such transactions are conducted in accordance with the risk management policy that has been approved by the Board of Directors.

BOE PRESENTATION

All amounts are expressed in Canadian dollars unless otherwise noted. Oil, natural gas and natural gas liquids reserves and volumes are converted to a common unit of measure, referred to as a barrel of oil equivalent (boe), on the basis of 6,000 cubic feet of natural gas being equal to one barrel of oil. This conversion ratio is based on an energy equivalency conversion method, primarily applicable at the burner tip and does not necessarily represent a value equivalency at the wellhead. It should be noted that the use of boe might be misleading, particularly if used in isolation.

FORWARD-LOOKING STATEMENTS

This MD&A 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 MD&A contains statements concerning: sustainability of production; forecast commodity prices, inflation rates and currency prices; the Company's long term prospects and business plan; Surge's assets and the characteristics thereof; estimates regarding the future values for certain of the Company's assets and liabilities; the potential extension of the Company's credit facility and the impact of the failure of the Company to secure an extension; the potential impact of the current economic environment on the Company; the COVID-19 pandemic and the potential impacts on the Company and the oil and gas industry generally; underlying causes of the fluctuations in Surge's revenue and net earnings from quarter to quarter; the ability of Surge to continue as a going concern; fair value of forward contracts, swaps, options and costless collars entered into by the Company; expected payments and forfeiture rates of RSAs and PSAs granted under the Company's Stock Incentive Plan; estimated tax pools; potential impairments and reversal of impairments of CGUs and the assumptions used to assess such potential impairments and reversals; expectations with respect to its underlying decommissioning liabilities; ability of Surge to avoid default under its credit facility or its convertible debentures; the Company's plans for funding its future capital requirements; the ongoing assessment of management and the Board of market conditions and other relevant considerations; expectations on factors affecting the royalty rates applicable to the Company; the Sale and the terms, timing and anticipated proceeds and benefits therefrom; the expected impact of the Sale on Surge's bank indebtedness and liquidity; and the anticipated terms of Surge's re-determined credit facilities.

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, recoverable and carrying value of certain assets, the financial assumptions used by Surge's reserve evaluators in assessing potential impairment of Surge assets; development and completion activities and the costs relating thereto, 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 and any acquired assets, the successful application of drilling, completion and seismic technology, the determination of decommissioning liabilities, the ability to obtain approval from syndicate to increase or maintain its credit facility; prevailing weather conditions, exchange rates, licensing requirements, the impact of completed facilities on operating costs, and the availability, 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; inability of Surge to fund its future capital requirements; 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; failure to obtain the continued support of the lenders under Surge's current bank line; potential decrease in the available lending limits under Surge's bank line as a result of the syndicate's interpretation of the Company's reserves, commodity prices and decommissioning obligations; or the inability to obtain consent of lenders to increase or maintain the bank line. Certain of these risks are set out in more detail in this MD&A under the headings 'Matters Relating to the COVID-19 Pandemic' and 'Risk Factors' herein and in Surge's AIF dated March 9, 2021 which has been filed on SEDAR and can be accessed at www.sedar.com.

The forward-looking statements contained in this MD&A 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.

NON-GAAP FINANCIAL MEASURES

Certain secondary financial measures in this document - namely, "adjusted funds flow", "adjusted funds flow per share", "net debt", "net operating expenses", "operating netback", and "adjusted funds flow per boe" are not prescribed by GAAP. These non-GAAP 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 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 financial measures used in this document are defined below.

Adjusted funds flow & Adjusted funds flow per share

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. Cash settled transaction and other costs represent expenditures associated with acquisitions, 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 calculated using the same weighted average basic and diluted shares used in calculating income per share.

		Three Months Ended	Years Ended Dec 31,
($000s except per share)	Dec 31, 2020	Sep 30, 2020	Dec 31, 2019	2020	2019
Cash flow from operating activities	11,000	15,082	34,474	72,190	149,417
Change in non-cash working capital	(5,084)	(2,622)	2,876	(16,721)	16,569
Decommissioning expenditures	2,551	63	1,425	4,305	5,522
Cash settled transaction and other
costs	—	—	106	98	1,480
Adjusted funds flow	$8,467	$12,523	$38,881	$59,872	$172,988
Per share - basic	$0.02	$0.04	$0.12	$0.18	$0.55

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

Net Debt

There is no comparable measure in accordance with IFRS for net debt. Net debt is calculated as bank debt, term debt, dividends payable plus the liability component of the convertible debentures plus or minus working capital, 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 timing of settlement of these balances.

		As at
($000s)	Dec 31, 2020	Sep 30, 2020	Dec 31, 2019
Bank debt	(260,908)	(296,055)	(316,404)
Term debt	(32,718)	—	—
Accounts receivable	29,796	25,205	41,486
Prepaid expenses and deposits	5,253	4,900	4,875
Accounts payable and accrued liabilities	(51,265)	(33,507)	(40,848)
Convertible debentures	(71,181)	(70,536)	(68,699)
Dividends payable	—	—	(2,719)
Total	(381,023)	(369,993)	(382,309)

Operating Netback & Adjusted Funds Flow per boe

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

Operating Netback & Adjusted Funds Flow per boe

	Three Months Ended						Years Ended Dec 31,
($000s)		Dec 31, 2020		Sep 30, 2020		Dec 31, 2019	2020		2019
Petroleum and natural gas revenue		59,907		56,931		91,790	211,049		394,349
Processing income		1,006		934		1,563	4,772		4,303
Royalties		(6,493)		(6,285)		(13,096)	(24,498)		(51,837)
Realized gain (loss) on commodityand FX contracts		(6,247)		(2,627)		248	20,099		(4,679)
Operating expenses		(26,531)		(23,204)		(29,448)	(101,640)		(116,338)
Transportation expenses		(1,892)		(2,187)		(2,624)	(9,766)		(11,866)
Operating netback		19,750		23,562		48,433	100,016		213,932
G&A expense		(2,968)		(3,000)		(3,640)	(12,486)		(14,287)
Interest expense		(8,315)		(8,039)		(5,911)	(27,658)		(26,657)
Adjusted funds flow		8,467		12,523		38,881	59,872		172,988
Barrels of oil equivalent (boe)		1,596,718		1,572,407		1,869,819	6,579,239		7,728,923
Operating netback ($ per boe)	$	12.37	$	14.99	$	25.91	$15.21	$	27.66
Adjusted funds flow ($ per boe)	$	5.30	$	7.97	$	20.80	$9.11	$	22.36

Net Operating Expenses

Net operating expenses are 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 in the MD&A.