Surge Energy Inc. announces third quarter financial & operating results

CALGARY, AB – Surge Energy Inc. (“Surge” or the “Company“) (TSX: SGY) is pleased to announce its financial and operating results for the quarter ended September 30, 2021.

The Company’s financial and operating results for the third quarter of 2021 include only a partial quarter of operational and financial contribution from the previously announced acquisition of Astra Oil Corp. (“Astra”), which closed on August 18, 2021. Additionally, Surge’s financial and operating results for the third quarter of 2021 include no impact from the previously announced acquisition of Fire Sky Energy Inc. (“Fire Sky”), which closed on November 1, 2021.

MESSAGE TO SHAREHOLDERS

During the third quarter of 2021, Surge completed the strategic acquisition of Astra Oil Corp. (“Astra”), adding highly concentrated light oil reserves, production, land, and operations in SE Saskatchewan. Subsequent to the quarter, on November 1, 2021 the Company announced the closing of the acquisition of Fire Sky Energy Inc. (“Fire Sky”), a private company with light oil assets focused in SE Saskatchewan for total consideration of $58 million. The Fire Sky acquisition expands Surge’s position in its new SE Saskatchewan core area, adding an additional 1,500 boepd of light oil production.

These two strategic acquisitions are consistent with Surge’s defined business model of acquiring high quality, operated, light and medium gravity, conventional crude oil reservoirs with large original oil in place (“OOIP¹) and low recovery factors. Following these acquisitions, Surge is now a 21,500 boepd (86 percent liquids) intermediate light and medium gravity oil producer, with over 975 internally estimated net development drilling locations², providing an estimated 13 year development drilling inventory².

In addition to the acquisitions the Company has now completed its 2H/21 23 gross (23.0 net) well Sparky drilling program, with a 100% success rate. All of the wells from the 2H/21 Sparky drilling program are scheduled to be on stream and optimized prior to the end of November 2021.

During the third quarter of 2021, Surge’s cash flow from operating activities increased by 218 percent, from $8.3 million in Q2/21 to $26.3 million in Q3/21. Additionally, the Company’s adjusted funds flow³ also increased by 105 percent, from $13.6 million in Q2/21 to $27.8 million in Q3/21.

Surge’s cash flow from operating activities and adjusted funds flow in Q3/21 were negatively impacted by realized losses on fixed price commodity contracts, totaling $23.2 million. These required fixed priced oil hedge positions were primarily entered into during the volatile price environment in 2020. Surge projects that, at current strip oil prices, the cash flow impact from these hedge positions will moderate significantly in the coming months as the hedges expire.

Production in Q3/21 averaged 17,642 boepd, up 17 percent from Q2/21 production levels of 15,132 boe per day. The Company’s Q3/21 production levels included only a partial quarter of production from the Astra acquisition and no impact from the Fire Sky acquisition.

FINANCIAL AND OPERATING HIGHLIGHTS	Three Months Ended September 30,			Nine Months Ended September 30,
($000s except per share amounts)	2021	2020	% Change	2021	2020	% Change
Financial highlights
Oil sales	97,272	54,000	80 %	243,639	143,643	70 %
NGL sales	2,663	1,161	129 %	6,437	2,868	124 %
Natural gas sales	5,170	1,770	192 %	16,606	4,631	259 %
Total oil, natural gas, and NGL revenue	105,104	56,931	85 %	266,682	151,142	76 %
Cash flow from operating activities	26,263	15,082	74 %	50,067	61,190	(18)%
Per share – basic ($)	0.46	0.38	21 %	1.07	1.55	(31)%
Per share diluted ($)	0.45	0.38	18 %	1.05	1.55	(32)%
Adjusted funds flow¹	27,804	12,523	122 %	57,118	51,405	11 %
Per share – basic ($)¹	0.48	0.32	50 %	1.22	1.31	(7)%
Per share diluted ($)	0.47	0.32	47 %	1.20	1.31	(8)%
Net income (loss)	67,612	(13,184)	(613)%	364,740	(689,570)	(153)%
Per share basic ($)	1.18	(0.33)	(458)%	7.82	(17.51)	(145)%
Per share diluted ($)	1.15	(0.33)	(448)%	7.63	(17.51)	(144)%
Total exploration and development expenditures	33,932	2,477	nm²	81,330	38,497	111 %
Total acquisitions & dispositions	90,000	(762)	nm	(12,591)	(6,038)	109 %
Total capital expenditures	123,932	1,715	nm	68,739	32,459	112 %
Net debt¹, end of period	319,790	369,993	(14)%	319,790	369,993	(14)%

Operating highlights
Production:
Oil (bbls per day)	14,264	13,759	4 %	13,299	14,817	(10)%
NGLs (bbls per day)	575	582	(1)%	560	558	– %
Natural gas (mcf per day)	16,815	16,503	2 %	15,582	16,857	(8)%
Total (boe per day) (6:1)	17,642	17,092	3 %	16,456	18,185	(10)%
Average realized price (excluding hedges):
Oil ($ per bbl)	74.12	42.66	74 %	67.11	35.38	90 %
NGL ($ per bbl)	50.31	21.68	132 %	42.13	18.76	125 %
Natural gas ($ per mcf)	3.34	1.17	185 %	3.90	1.00	290 %

Netback ($ per boe)
Petroleum and natural gas revenue	64.76	36.21	79 %	59.36	30.33	96 %
Realized gain (loss) on commodity and FX contracts	(14.30)	(1.67)	756 %	(13.57)	5.29	(357)%
Royalties	(9.55)	(4.00)	139 %	(7.80)	(3.61)	116 %
Net operating expenses¹	(16.83)	(14.16)	19 %	(17.57)	(14.32)	23 %
Transportation expenses	(1.11)	(1.39)	(20)%	(1.03)	(1.58)	(35)%
Operating netback¹	22.97	14.99	53 %	19.39	16.11	20 %
G&A expense	(2.06)	(1.91)	8 %	(2.08)	(1.91)	9 %
Interest expense	(3.78)	(5.11)	(26)%	(4.60)	(3.88)	19 %
Adjusted funds flow¹	17.13	7.97	115 %	12.71	10.32	23 %


Common shares outstanding, end of period³	72,177	39,975	81 %	72,177	39,975	81 %
Weighted average basic shares outstanding³	57,380	39,661	45 %	46,662	39,388	18 %
Stock option dilution	1,243	–	nm	1,127	–	nm
Weighted average diluted shares outstanding³	58,623	39,661	48 %	47,789	39,388	21 %

¹This is a non-GAAP financial measure which is defined in the Non-GAAP Financial Measures section of this document.
²The Company views this change calculation as not meaningful, or “nm”.
³The number of common shares has been adjusted retrospectively to reflect the 8:5:1 share consolidation that was approved by the Corporation’s shareholders on August 17, 2021.

UPDATE ON ENVIRONMENTAL, SOCIAL AND GOVERNANCE MATTERS (“ESG”)

Surge continues to reduce the impact of its operations on the environment and is pleased to report that it has abandoned over 190 wells in the first nine months of 2021. The Company spent $3.0 million on abandonment activities during the third quarter of 2021 and has now spent $6.6 million to date during 2021. These activities included the abandonment of inactive well bores and the decommissioning of inactive pipelines throughout its operating areas.

Additionally, Surge has now completed the previously announced 45-kilometer gas gathering infrastructure system in SE Saskatchewan. This pipeline allows the Company to conserve gas at critical facilities and is anticipated to reduce emissions by over 95 percent from its main operating fields in the area.

Surge strives to be a leader in reducing the impact of its operations on the environment and is committed to producing energy in a safe, responsible, and sustainable manner.

OUTLOOK – A TOP PERFORMER IN 2022

Management remains excited regarding the Company’s exposure to rising crude oil prices in 2022, following its strategic positioning activities throughout 2021. The Company anticipates generating significantly higher operating netbacks and cash flow from operating activities in 2022 at current commodity prices.

Surge is now a 21,500 boepd (86 percent liquids) intermediate light and medium gravity oil producer, with over 975 net internally estimated development drilling locations, providing an estimated 13 year development drilling inventory.

Surge’s upwardly revised exit 2021 and preliminary 2022 guidance is reconfirmed as follows:

Guidance	@ US $70 WTI*	@ US $75 WTI*	@ US $80 WTI*
Exit 2021 production	21,500 boepd (86% liquids)
Average 2022 production	21,500 boepd (86% liquids)
2022 Exploration and Development Capital Expenditures	$120 million
2022 Adjusted funds flow ($MM)	$245	$270	$295
Per share	$2.94/share	$3.23/share	$3.53/share
2022 Cash flow from operating activities ($MM)	$230	$255	$280
Per share	$2.76/share	$3.05/share	$3.35/share
2022 Free cash flow ($MM)⁴	$110	$135	$160
Per share	$1.32/share	$1.62/share	$1.92/share
2022 All-in payout ratio⁴	52%	47%	43%
2022 Net debt to annualized Q4/22 adjusted funds flow⁴	0.7x	0.6x	0.5x

*All additional pricing assumptions (WCS: US$13.50, EDM US$4.00), Fx of $0.80 and AECO of $3.00 per mcf remain constant. Adjusted funds flow and cash flow from operating activities includes estimated realized gain (loss) on financial contracts, and assumes a nil change in non-cash working capital.

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⁴	This is a non-GAAP financial measure which is defined in the Non-GAAP Financial Measures section of this document.

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 with respect to management’s expectations regarding commodity prices; Surge’s declared focus and primary goals; the acquisition of all of the outstanding shares of Fire Sky and the anticipated benefits and timing thereof; management’s expectations regarding the reduction of net debt and free cash flow generation; guidance regarding exit 2021 production and exit 2022 net debt; Surge’s hedging program; Surge’s planned drilling program; Surge’s drilling inventory and locations; management’s expectations and plans with respect to the development of its assets and the timing thereof; netbacks; production levels; amendments to Surge’s credit facilities; and Surge’s ongoing ESG initiatives, including abandonment activities and Surge’s participation in emissions reduction and gas conservation programs.

The forward-looking statements are based on certain key expectations and assumptions made by Surge, including expectations and assumptions the performance of existing wells and success obtained in drilling new wells; anticipated expenses, cash flow and capital expenditures; the application of regulatory and royalty regimes; 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 9, 2021 and in Surge’s MD&A for the period ended December 31, 2020, 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.

Advisories & Contact

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. All oil and gas metrics/terms used in this document are defined below:

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 Jan 1, 2021.

Drilling Inventory

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

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

Net of Surge March 25, 2021 disposition, the pro forma Company (Surge + Astra + Fire Sky) will have over >1,050 gross (>975 net) drilling locations identified herein, of these >450 gross (>400 net) are unbooked locations. Of the 562 net booked locations identified herein, 415 net are Proved locations and 147 net are Probable locations based on Sproule’s 2020YE reserves. Assuming an average number of net wells drilled per year of 75, Surge’s >975 net locations provide 13 years of drilling.

Surge’s internally developed type curves (for Surge, Astra and Fire Sky) were constructed using a representative, factual and balanced analog data set, as of Jan 1, 2021 for Surge type curves, April 15, 2021 for Astra type curves and July 1, 2021 for Fire Sky type curves. All locations were risked appropriately, and EUR’s were measured against OOIP estimates to ensure a reasonable recovery factor was being achieved based on the respective spacing assumption. Other assumptions, such as capital, operating expenses, wellhead offsets, land encumbrances, working interests and NGL yields were all reviewed, updated and accounted for on a well by well basis by Surge’s Qualified Reserve Evaluators. All type curves fully comply with Part 5.8 of the Companion Policy 51 – 101CP.

Non-GAAP Financial Measures

Certain secondary financial measures in this press release – namely, “adjusted funds flow”, “adjusted funds flow per share”, “all-in payout ratio”, “free cash flow”, “net debt”, “operating netback”, “net debt to annualized Q4/22 adjusted fund flow”, “net operating expenses” 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. Transaction and other costs represent expenditures associated with acquisitions 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 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 for the three and nine months ended September 30, 2021:

	Three Months Ended September 30,				Nine Months Ended September 30,
($000s except per share amounts)	2021		2020		2021		2020
Cash flow from operating activities	26,263		15,082		50,067		61,190
Change in non-cash working capital	(2,866)		(2,622)		(2,485)		(11,637)
Decommissioning expenditures	2,105		63		4,649		1,754
Cash settled transaction and other costs	2,303		–		4,888		98
Adjusted funds flow	$	27,804	$	12,523	$	57,118	$	51,405
Per share – basic	$	0.48	$	0.32	$	1.22	$	1.31

The following table reconciles forecast cash flow from operating activities to adjusted funds flow along with operating netback.

	2022e
($millions)	@ US $70 WTI	@ US $75 WTI	@ US $80 WTI
Petroleum and natural gas revenue	495	539	580
Royalties	(68)	(74)	(79)
Net operating expenses	(118)	(118)	(118)
Transportation expenses	(9)	(9)	(9)
Loss on financial contracts	(21)	(34)	(45)
Operating netback	279	304	329
G&A expense	(14)	(14)	(14)
Interest expense	(20)	(20)	(20)
Adjusted funds flow	245	270	295
Changes in non-cash working capital	–	–	–
Lease repayments	(9)	(9)	(9)
Abandonments	(6)	(6)	(6)
Cash flow from operating activities	230	255	280
Barrels of oil equivalent (mmboe)	7.8	7.8	7.8

All-in payout ratio

All-in payout ratio is calculated as exploration and development expenditures divided by adjusted funds flow.

Free Cash Flow and Free Cash Flow per Share

Free cash flow is calculated as cash flow from operating activities less exploration and development capital expenditures. Management uses free cash flow to determine the amount of funds available to the Company for future capital allocation decisions.

Free cash flow per share is calculated using the same weighted average basic and diluted shares used in calculating income per share and adjusted funds flow per share.

Net Debt and Net Debt to Annualized Q4/22 Adjusted Fund Flow

There is no comparable measure in accordance with IFRS for net debt. Net debt is calculated as bank debt, term debt, 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.

($000s)	As at Sep 30, 2021	As at Jun 30, 2021	As at Sep 30, 2020
Accounts receivable	58,968	29,244	25,205
Prepaid expenses and deposits	4,044	4,595	4,900
Accounts payable and accrued liabilities	(73,009)	(50,641)	(33,507)
Bank debt	(189,371)	(162,318)	(296,055)
Term debt	(47,203)	(41,164)	–
Convertible debentures	(73,219)	(72,522)	(70,536)
Net Debt	(319,790)	(292,806)	(369,993)

Net debt to annualized Q4/22 adjusted funds flow is calculated as net debt divided by annualized three month adjusted funds flow (adjusted funds flow for the quarter multiplied by four). Management uses this ratio to assess the period of time that it would take to fund net debt based on the adjusted funds flow from the quarter.

Operating Netback & Adjusted Funds Flow per boe

Operating netback and adjusted funds flow per boe for the three and nine months ended September 30, 2021 are calculated on a per unit basis as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
($000s)	2021		2020		2021		2020
Petroleum and natural gas revenue	105,104		56,931		266,682		151,142
Processing and other income	978		934		3,239		3,766
Royalties	(15,501)		(6,285)		(35,051)		(18,005)
Realized gain (loss) on commodity and FX contracts	(23,209)		(2,627)		(60,942)		26,346
Operating expenses	(28,288)		(23,204)		(82,156)		(75,109)
Transportation expenses	(1,798)		(2,187)		(4,630)		(7,874)
Operating netback	37,286		23,562		87,142		80,266
G&A expense	(3,346)		(3,000)		(9,344)		(9,518)
Interest expense	(6,135)		(8,039)		(20,679)		(19,343)
Adjusted funds flow	27,804		12,523		57,118		51,405
Barrels of oil equivalent (boe)	1,623,036		1,572,407		4,492,511		4,982,521
Operating netback ($ per boe)	$	22.97	$	14.99	$	19.39	$	16.11
Adjusted funds flow ($ per boe)	$	17.13	$	7.97	$	12.71	$	10.32

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.

Additional information relating to non-GAAP measures can be found in the Company’s most recent management’s discussion and analysis MD&A, which may be accessed through the SEDAR website (www.sedar.com).

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