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Surge Energy Inc. Announces Completion of Upsized Bought Deal Flow-Through Financing; Extension of First Lien Credit Facilities Into the Second Half of 2022; Preliminary 2022 Guidance


CALGARY, AB, May 13, 2021 /CNW/ – Surge Energy Inc. (“Surge” or the “Company”) (TSX: SGY) is pleased to announce it has closed the previously announced bought deal public offering (the “Offering”) of flow-through common shares (“Flow-Through Shares”). Surge is also pleased to announce that its first lien credit facilities have been extended through to July 1, 2022. Additionally, the Company is announcing 2021 production exit guidance and preliminary 2022 capital and operating guidance.

EQUITY FINANCING CLOSED

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Surge Energy Inc. Announces Completion of Upsized Bought Deal Flow-Through Financing; Extension of First Lien Credit Facilities Into the Second Half of 2022; Preliminary 2022 Guidance (CNW Group/Surge Energy Inc.)

Surge has completed the upsized, over-subscribed Offering, and is pleased to announce the underwriters have elected to exercise in full their option to purchase additional Flow-Through Shares, equal to 15% of the number of Flow-Through Shares sold pursuant to the Offering. On this basis, the Company has issued 38,985,000 Flow-Through Shares at a price of $0.59 per Flow-Through Share, for total gross proceeds of $23,001,150. The syndicate of underwriters for the Offering was led by Cormark Securities Inc. and National Bank Financial Inc.

EXTENSION OF CREDIT FACILITIES INTO THE SECOND HALF OF 2022

The Company is also pleased to announce that, concurrent with the closing of the Offering, the maturity of its first lien credit facilities has been extended from December 30, 2021 to July 1, 2022.

2H 2021 AND PRELMINARY 2022 GUIDANCE 

Proceeds from the Offering, combined with free cash flow, will be used for an expanded 2H/21 development program, building upon the Company’s successful 1H/21 drilling program, which targeted the Sparky and Montney formations. The 2H/21 program is strategically designed to allocate additional capital towards top-tier production efficiencies in the Company’s Sparky core area.

The 2H/21 capital program involves drilling up to 23 gross (23.0 net) wells in four distinct, large original oil in place (“OOIP”)1, shallow, conventional Sparky sandstone reservoirs. This targeted drilling program is expected to result in production additions of more than 2,400 boe per day for total drilling and completions expenditures of $32 million, resulting in production efficiencies of $13,250 per flowing boe on an IP180 basis1.

The expanded 2H/21 capital program is anticipated to deliver over 6 percent of cash flow per share growth for Surge’s shareholders in the current year (ie. in Q4/21), when compared to the Company’s previously planned 2H/21 maintenance-only capital program.

The Company’s preliminary 2022 capital expenditure budget will continue to focus on production maintenance and free cash flow generation. Surge anticipates generating approximately $160 million ($0.42 per share2) in adjusted funds flow3 in 2022 at current oil prices of approximately US$65 WTI per barrel. With its low decline, shallow, large OOIP, conventional asset base, the Company is budgeting $83 million for its 2022 exploration & development capital program, maintaining production at 16,500 boepd (85% liquids).

On this basis, Surge anticipates generating $62 million ($0.16 per share) of free cash flow4 in 2022, representing a free cash flow yield5 of approximately 28 percent for the year.

Based upon the above, the Company’s 2H 2021 and preliminary 2022 guidance is as follows:

US $WTI per bbl $65 WTI6 $60 WTI6
Total 2021(e) Exploration & Development Capital $89 million
Exit 2021(e) Production 16,500 boepd (85% liquids)
Total 2022(e) Exploration & Development Capital $83 million
Average & Exit 2022(e) Production 16,500 boepd (85% liquids)
2022(e) Cash flow From Operating Activities $145 million $121 million
Per share $0.38/share $0.32/share
2022(e) Adjusted Funds Flow $160 million $136 million
Per share $0.42/share $0.36/share
2022(e) Net Operating Expenses5 $16.45 – $16.95 per boe
2022(e) Transportation Expenses $1.20 – $1.30 per boe
2022(e) General & Administrative Expenses $1.95 – $2.05 per boe

Both the Company’s 2H/21 and preliminary 2022 capital program continue to focus capital on Surge’s extensive, 14 year drilling inventory of over 425 net Sparky core area locations7 – across multiple large OOIP, shallow, conventional reservoirs.

__________________
1 See the Oil and Gas Advisories section of this document for further details.
2 All per-share metrics in this release are based on 378.8 million basic shares outstanding as at close of the Offering.
3 See the Non-GAAP Financial Measures section of this document for further details.
4 See the Non-GAAP Financial Measures section of this document for further details.
5 Calculated as free cash flow per share of $0.16 divided by a SGY share price of $0.58 per share.
6 Pricing used as follows: WTI US$65/bbl; CAD/USD $0.80; WCS $66.25/bbl; MSW $75.62 bbl; AECO $2.55/GJ.
WTI US$60/bbl; CAD/USD $0.80; WCS $60.35/bbl; MSW $69.75bbl; AECO $2.55/GJ.
7 See the Drilling Inventory section of this document for further details.

OUTLOOK: EXCITING 1H/21 DRILLING RESULTS

The Company will bring on an estimated 3,400 boepd of production from its 32 well 1H/21 drilling program, with results to date meeting or exceeding budgeted expectations. This production was added for “all-in” drilling and completion expenditures of $38 million, delivering production efficiencies of $11,175 per boe.

Over the last six years, Surge has amassed a dominant position in its core Sparky crude oil play, which is proving to be one of the premier, conventional, medium/light oil growth plays in Canada. Surge estimates a weighted average (risked) IRR of greater than 140 percent7 for the Company’s entire 425 net well (14 year) Sparky core area drilling inventory at US $60 WTI per barrel flat pricing. These excellent risked returns are for primary drilling only, and do not include waterflood upside.

With crude oil prices now up over 450%8 in the last 13 months, combined with the Company’s 85% oil and natural gas liquids weighting, Surge believes it is well-positioned to deliver continued cash flow per share growth and a free cash flow yield in 2022.

__________________
8 From WTI US$11.57 per barrel in April of 2020 to over US$66 per barrel on May 11th, 2021.

FORWARD LOOKING STATEMENTS:

This press release contains forward-looking statements. The use of any of the words “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “should”, “believe” and similar expressions are intended to identify forward-looking statements. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements.

More particularly, this press release contains statements concerning: Management’s expectations and plans with respect to the development of its assets and the timing thereof; Surge’s declared focus and primary goals; Surge’s planned drilling program for 2H/21 and the potential for revisions thereto; Surge’s drilling inventory and locations; management’s expectations regarding commodity prices; the expected impact of the Sale on Surge’s bank indebtedness and liquidity; management’s expectations regarding 2021 production and management’s expectations regarding DCET costs; and the anticipated terms and benefits of the re-determination of Surge’s credit facilities and the timing thereof.

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.

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.

Production efficiencies are calculated by dividing 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.

Assuming a Mar 31, 2021 reference date, the Company will have over >425 gross (>425 net) Sparky core area drilling locations identified herein, of these >150 gross (>150 net) are booked locations. Of the >150 net booked locations identified herein, 113 net are Proved locations and 39 net are Probable locations based on Sproule’s 2020YE reserves. Assuming an average number of wells drilled per year of 30, Surge’s >425 locations provide 14 years of drilling.

Surge’s internally used type curves were constructed using a representative, factual and balanced analog data set, as of January 1, 2021. 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.

Surge’s weighted average internal Sparky type curve economics have an IRR of greater than 140% @ US$60/bbl WTI (C$62 WCS) and are supported by >380 internally evaluated Sparky locations by Surge’s Qualified Reserve Evaluators (with weighted average metrics of: ~$1.15 MM per well capital, ~105 boe/d IP180 per well and ~125 mboe Estimated Ultimate Recoverable reserves per well).

Non-GAAP Financial Measures

Certain secondary financial measures in this press release – namely, “adjusted funds flow” and “net operating expenses” 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 transaction 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 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.

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

2022e
($millions)  $65 WTI   $60 WTI 
Petroleum and natural gas revenue $348.0 $319.4
Royalties ($40.1) ($36.8)
Net operating expenses ($100.6) ($100.6)
Transportation expenses ($7.5) ($7.5)
Loss on financial contracts ($4.6) ($2.9)
Operating netback $195.2 $171.7
G&A expense ($12.0) ($12.0)
Interest expense ($23.2) ($23.6)
Adjusted Funds Flow $160.0 $136.0
Changes in non-cash working capital $0.0 $0.0
Lease repayments ($9.0) ($9.0)
Abandonments ($6.0) ($6.0)
Cash flow from Operating Activities $145.0 $121.0

Free Cash Flow & 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 Operating Expenses

Net operating expenses are determined by deducting processing and other revenue 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.

Neither the TSX nor its Regulation Services Provider (as that term is defined in the policies of the TSX) accepts responsibility for the adequacy or accuracy of this release.

SOURCE Surge Energy Inc.

For further information: Paul Colborne, President & CEO, Surge Energy Inc., Phone: (403) 930-1507, Fax: (403) 930-1011, Email: pcolborne@surgeenergy.ca; Jared Ducs, Chief Financial Officer, Surge Energy Inc., Phone: (403) 930-1046, Fax: (403) 930-1011, Email: jducs@surgeenergy.ca

Related Links

http://www.surgeenergy.ca



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