Surge Energy Inc. announces closing of $58 million Southeast Saskatchewan light oil acquisition; upward revision to 2022 guidance

CALGARY, AB – Surge Energy Inc. (“Surge” or the “Company”) (TSX: SGY) is pleased to announce the completion of the previously announced acquisition of Fire Sky Energy Inc. (“Fire Sky”) pursuant to an amalgamation (the “Transaction”) under the provisions of The Business Corporations Act (Saskatchewan).

FIRE SKY ACQUISITION CLOSED

Surge has been advised by Fire Sky that the amalgamation was approved by 97.6% of the Fire Sky Shares voted at the special meeting of Fire Sky shareholders to approve the Transaction, held on October 27, 2021.

The purchase price payable by Surge under the Transaction was $58 million, comprised of: 1) the issuance of approximately 11.2 million Surge common shares; and 2) the assumption of approximately $3.0 million of Fire Sky net debt¹, inclusive of transaction costs.

CORPORATE OUTLOOK; UPWARD REVISISION TO PRELIMINARY 2022 GUIDANCE

Surge anticipates significant free cash flow¹generation (at current strip pricing) in 2022, through consistent and disciplined development of its high quality, conventional crude oil asset base, including Surge’s premier Sparky play in Alberta, complemented by its high operating netback¹, light oil Southeast Saskatchewan assets.

Following the completion by Surge and Fire Sky of their respective drilling programs to date in 2021, Surge anticipates achieving its previously announced guidance for the Company’s 2021 exit production rate of 21,500 boepd.

Surge confirms the Company’s upwardly revised financial and operational guidance for 2022, as detailed below:

Guidance	@ US $75 WTI*	@ US $80 WTI*	@ US $85 WTI*
Exit 2021 production	21,500 boepd (86% liquids)
Average 2022 production	21,500 boepd (86% liquids)
2022 Exploration and Development Capital Expenditures	$120 million
2022 Adjusted funds flow¹ ($MM)	$270	$295	$315
2022 Adjusted funds flow per share¹	$3.23	$3.53	$3.77
2022 Cash flow from operating activities ($MM)	$255	$280	$300
2022 Free cash flow ($MM)	$135	$160	$180
2022 Free cash flow per share	$1.62	$1.92	$2.16
2022 All-in payout ratio¹	47%	43%	40%
2022 Exit Net debt to annualized Q4/22 adjusted funds flow¹	0.6x	0.5x	0.4x

*All additional pricing assumptions (WCS: US$13.50, EDM US$5.00), Fx of $0.80 and AECO of $2.50 per mcf) remain constant. Adjusted funds flow and cash flow from operating activities assume $nil change in non-cash working capital.

Following the completion of the Transaction, Surge has the following operational indicia and financial attributes:

Over 2.6 billion barrels of net combined, internally estimated, conventional OOIP²– with a recovery factor to date of 6 percent;
Combined proven plus probable year end 2020 reserves of over 100 million boe (86 percent liquids), generating a 13 year reserve life index;
Exit 2021 production forecast of 21,500 boepd (86 percent liquids weighted);
Estimated base corporate decline of 26 percent;
A development drilling inventory of over 975 net locations (internally estimated)³; providing a development drilling inventory of more than 13 years;
Production efficiencies² of ~$15,600 per boepd (IP 180);
Shares outstanding (basic): 83.4 million; and
An estimated exit 2022 net debt to annualized Q4/22 adjusted funds flow of approximately 0.6 times at US$75 WTI.

ADVISORS

National Bank Financial Inc. acted as exclusive financial advisor, and ATB Capital Markets and Scotiabank acted as strategic advisors, to Surge with respect to the Transaction. McCarthy Tétrault LLP acted as legal advisor to Surge with respect to the Transaction.

Peters & Co. Ltd. acted as exclusive financial advisor to Fire Sky. TingleMerrett LLP acted as legal advisor to Fire Sky with respect to the Transaction.

FORWARD LOOKING STATEMENTS:

This news release includes statements containing certain “forward-looking information” within the meaning of applicable securities law (“forward-looking statements”). Forward-looking-statements in this release include, but are not limited to, the opinions and beliefs of management. Forward-looking statements are frequently characterized by words such as “plan”, “continue”, “expect”, “project”, “intend”, “believe”, “anticipate”, “estimate”, “may”, “will”, “potential”, “proposed” and other similar words, or statements that certain events or conditions “may” or “will” occur. 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.

Various assumptions were used in drawing the conclusions or making the projections contained in the forward-looking statements throughout this news release. Forward-looking statements are based on the opinions and estimates of management at the date the statements are made, and are subject to a variety of risks and uncertainties and other factors that could cause actual events or results to differ materially from those projected in the forward-looking statements.

More particularly, this press release contains statements concerning management’s expectations and assumptions concerning the anticipated benefits of the Transaction and the transaction metrics related thereto; Surge’s revised guidance for the remainder of 2021 and preliminary guidance for 2022; and management’s beliefs and expectations regarding its OOIP, drilling inventory, decline rates; exit 2021 production; and estimated 2022 exit net debt

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 year 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, and expressly disclaims any intention or 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.

Net of Surge disposition from March 25, 2021, the pro forma Company (Surge + Astra + Fire Sky) will have 2020YE TPP reserves of 104.5mmboe. Fire Sky reserves have been evaluated by Sproule from 2016YE through to 2020YE. Similarly, Sproule has evaluated all of Surge’s assets from 2015YE to 2020YE.

Production efficiencies are calculated by dividing drilling, completion, equipping and tie in capital expenditures of a project by the average production from that project for a given period of time. IP180 is the average production rate of a well over the first 180 days on production.

Drilling Inventory

This press release discloses drilling locations in two categories: (i) booked locations; and (ii) unbooked locations. Booked locations are proved locations and probable locations derived from an internal evaluation using standard practices as prescribed in 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.

Surge’s review of Fire Sky’s inventory supports > 100 gross (>100 net) internally estimated drilling locations. Fire Sky’s February 2021 Year End reserves has 118.4 net booked locations. Of these, 68.2 net are Proved locations and 50.2 net are Probable locations based on Sproule’s evaluation.

Net of Surge March 25, 2021 disposition, the pro forma Company (Surge + 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 both Surge and Fire Sky) were constructed using a representative, factual and balanced analog data set, as of Jan 1, 2021 for Surge 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 – including, “adjusted funds flow”, “operating netback”, “free cash flow”, “all-in payout ratio”, and “net debt”, 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 (per share) and Operating Netback

The Company adjusts cash flow from operating activities in calculating adjusted funds flow for changes in decommissioning expenditures and transaction costs. 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 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 shares used in calculating income per share.

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


	2022e
($millions)	@ US $75 WTI	@ US $80 WTI	@ US $85 WTI
Petroleum and natural gas revenue	539	580	622
Royalties	(74)	(79)	(86)
Net operating expenses	(118)	(118)	(118)
Transportation expenses	(9)	(9)	(9)
Loss on financial contracts	(34)	(45)	(59)
Operating netback	304	329	350
G&A expense	(14)	(14)	(14)
Interest expense	(20)	(20)	(20)
Adjusted funds flow	270	295	315
Changes in non-cash working capital	–	–	–
Lease repayments	(9)	(9)	(9)
Abandonments	(6)	(6)	(6)
Cash flow from operating activities	255	280	300
Barrels of oil equivalent (mmboe)	7.8	7.8	7.8

Free Cash Flow

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.

All-in Payout Ratio

All-in payout ratio is calculated as exploration and development expenditures divided by cash flow from operating activities.

Net Debt and Net Debt to 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, 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.

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.

Additional information relating to non-IFRS 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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