CALGARY, Alberta, Nov. 02, 2022 (GLOBE NEWSWIRE) -- Surge Energy Inc. (“Surge”, “SGY”, or the “Company”) (TSX: SGY) is pleased to announce that it has entered into a definitive purchase and sale agreement (the “Definitive Agreement”) with Enerplus Corporation (“Enerplus” or “ERF”) pursuant to which Surge has agreed to acquire from Enerplus (the “Acquisition”) long life, operated, high operating netback1, waterflooded producing oil assets focused entirely within Surge’s Sparky and SE Saskatchewan core areas (the “Assets”).
Surge has agreed to purchase the Assets for gross proceeds of $245 million (the “Purchase Price”) with an effective date of May 1, 2022, payable to Enerplus by way of an estimated $165 million of cash, $45 million in estimated interim period adjustments, and $35 million of equity in the form of common shares of SGY (“Common Shares”) issued from treasury to Enerplus.
The Acquisition has an effective date of May 1, 2022 and is currently expected to close on or about December 19, 2022 (the “Closing”), with an estimated net purchase price after interim period adjustments of $200 million (the “Net Purchase Price”).
In conjunction with the Closing, Surge anticipates increasing the Company’s annual cash dividend by 14 percent, from $0.42 per share to $0.48 per share (paid monthly). Any dividend increase will be subject to the approval of Surge's Board of Directors with consideration given to the business environment at the time of Closing.
The Assets are currently producing more than 3,850 boepd (99 percent liquids) of predominantly light and medium gravity crude oil, with synergistic operations entirely focused in Surge’s existing Sparky and SE Saskatchewan core areas. With an operating netback of more than $48 per boe in 2023 (at flat US$80 WTI per bbl pricing2), the Assets are forecast to deliver $68 million of cash flow from operating activities and more than $50 million of free cash flow1 (“FCF”) after expenditures on property, plant, and equipment and abandonment expenditures required to maintain current production levels from the Assets.
After giving effect to the Acquisition, Surge is now forecasting upwardly revised exit 2022 production of more than 25,000 boepd, consisting of approximately 87 percent liquids, which is made up of predominantly light and medium gravity crude oil.
ASSET & ACQUISITION HIGHLIGHTS
- At flat US$80 WTI per bbl pricing, the Acquisition is accretive to Surge as follows:
- 17 percent accretive to Surge’s forecast 2023 FCF per share;
- 8 percent accretive to Surge’s forecast 2023 annual cash flow per share; and
- 8 percent accretive to Surge’s forecast 2023 annual production per share.
- The Assets are entirely focused in Surge’s existing SE Saskatchewan and Sparky core areas, and provide the following to Surge shareholders:
- Adds 3,850 boepd of sustainable, high operating netback, waterflooded, light and medium gravity crude oil production, with a low decline rate3 of approximately 12 percent;
- Fully waterflooded Assets reduce Surge’s corporate decline rate to approximately 23 percent, significantly enhancing corporate sustainability;
- Adds a high quality, synergistic development drilling inventory, which can hold production flat at the current rate of 3,850 boepd on the Assets for an estimated 7 years4;
- Adds approximately 400 million barrels of internally estimated original oil in place (“OOIP)3 net to Surge, with a low 14 percent recovery factor to date3; and
- Increases the Company’s total estimated OOIP to approximately 3.1 billion barrels, with a low combined recovery factor of 7.5 percent to date.
Paul Colborne, President and CEO of Surge, said: “We are very excited about this accretive, strategic, long life, core area Acquisition. This is one of the highest quality, low decline, asset packages that we have seen in my nine years at Surge. This Acquisition is consistent with Surge’s disciplined strategy of acquiring high quality, operated, conventional crude oil reservoirs with large original oil in place and low recovery factors. The Assets are under successful waterflood, providing significant proven developed producing (“PDP”) reserves, they possess a combined low 12 percent annual production decline3, and they provide a solid development drilling inventory which we estimate can hold production flat on the acquired Assets for seven years. In 2023, we estimate that production can be held flat using approximately 20 percent of 2023 annual cash flow from operating activities generated by the Assets at US$80 WTI flat pricing.”
“Over the past eight years, Surge has established a dominant position in its Sparky core growth area. With the Acquisition, we have added to that position and now have ownership and control of more than one billion barrels of net OOIP in the Company’s Sparky core area, with a 12 year drilling inventory4,” said Colborne. “Since 2014, Surge has sequentially grown production in the Sparky from 1,200 boepd to over 11,000 boepd by exit 2022.”
“More recently, Surge Management has strategically targeted SE Saskatchewan as a new core area of growth, based on its high value light oil operating netbacks, low cost production efficiencies, quick drilling payouts, and consolidation opportunities. Surge’s operational track record of execution in SE Saskatchewan, combined with its proven in-house technical expertise, make this an exciting growth area for the Company. The Acquisition adds approximately 1,950 bopd in SE Saskatchewan of 11 percent decline, light oil production that enhances our area sustainability. Surge now projects that the Company will exit 2022 with more than 7,500 boepd (94 percent light oil) in SE Saskatchewan.”
- The Acquisition is consistent with Surge’s disciplined return of capital business model, which is intended to provide substantial FCF for continued net debt repayment, sustainable dividend increases, sustainable production per share growth, and share buybacks;
- The Acquisition adds highly concentrated, long life, waterflooded, light and medium gravity crude oil reserves, production, land, and infrastructure which are synergistic with Surge’s Sparky and SE Saskatchewan core area operations;
- Following the Acquisition, Surge will exit 2022 with approximately 75 percent of the Company’s production focused in its Sparky and SE Saskatchewan core areas;
- Surge estimates that approximately 20 percent of the annual cash flow from operating activities generated by the Assets is needed to hold the production flat at approximately 3,850 boepd in 2023 at US$80 WTI per barrel;
- The Assets are very clean from an environmental perspective with less than $10 million of undiscounted inactive abandonment liabilities;
- The Assets have an attractive Licensee Liability Rating of 4.4 in Alberta and 2.9 in Saskatchewan; and
- The Assets include propriety operated and non-operated seismic data totaling 2,793 square kilometers of 3D data and 37,970 km of 2D data. This data significantly increases Surge’s seismic data in its core operating areas; increasing the Company’s 3D coverage by 2 times, and its 2D coverage by 5 times.
|Gross Purchase Price||$245 million|
|Estimated Net Purchase Price||$200 million|
|Annual Cash Flow from Operating Activitiesa||$68 million|
|Current Production Rate||~3,850 boepd (99 percent light & medium oil)|
|Proved Developed Producing Reservesb||10.1 MMboe (99 percent light & medium oil)|
|Total Proved plus Probable Reservesb||15.0 MMboe (99 percent light & medium oil)|
|Proved Developed Producing RLIc||6.8 years|
|Total Proved plus Probable RLIc||10.1 years|
|Estimated Net Purchase Price per boepd||$51,950/boepd|
|Operating Netback @ US$80 WTI||>$48/boe|
|Estimated Net Purchase Price over Proved Developed Producing Reservesb per boe||$19.80/boe|
|Estimated Net Purchase Price over Total Proved plus Probable Reservesb per boe||$13.33/boe (prior to Future Development Capital)|
|Proved Developed Producing Recycle Ratiod||2.4x|
|Proved plus Probable Recycle Ratioe||3.6x|
a: Based on the following pricing assumptions: US$80.00WTI/bbl; CAD$109.59WTI/bbl; EDM CAD$104.11/bbl; WCS CAD $85.62/bbl; AECO CAD$5/mcf
b: Based upon McDaniel’s 2021YE reserve estimate as of January 1, 2022.
c: Based upon McDaniel’s total proved plus probable reserve estimate as of January 1, 2022 divided by production of 4,053 boepd.
d: Recycle ratio is calculated as operating netback of $48/boe divided by the acquisition cost of proved developed producing reserves of $19.80/boe.
e: Recycle ratio is calculated as operating netback of $48/boe divided by the acquisition cost of proved plus probable reserves of $13.33/boe.
PRELIMINARY 2023 CAPITAL AND OPERATING BUDGET
In conjunction with the Acquisition, Surge’s preliminary financial and operational estimates for 2023 are detailed below:
|Guidance||@ US $80 WTI ($0.73 FX)a|
|Exit 2022 Production||>25,000 boepd (87% liquids)|
|Average 2023 Production||>25,000 boepd (87% liquids)|
|2023(e) Expenditures on property, plant and equipment||$190 million|
|2023(e) Cash Flow from Operating Activities||$360 million|
|2023(e) Free Cash Flow Before Dividends||$170 million|
|2023(e) Dividend||$44 million|
|2023(e) All-in Payout Ratioc||65%|
|2023(e) Royalties as % of Petroleum and Natural Gas Revenue||18.5%|
|2023(e) Net Operating Expensesc||$19.50 - $19.75 per boe|
|2023(e) Transportation Expenses||$1.25 - $1.50 per boe|
|2023(e) General & Administrative Expenses||$1.85 - $1.95 per boe|
a: Based on the following pricing assumptions: US$80.00WTI/bbl; CAD$109.59WTI/bbl; EDM CAD$104.11/bbl; WCS CAD $85.62/bbl; AECO $5/mcf
b: Based on 84 million Common Shares outstanding prior to the Acquisition, plus an estimated 7.8 million Common Shares issued in conjunction with the Acquisition
c: This is a non-GAAP and other financial measure which is defined in the Non-GAAP and Other Financial Measures section of this document
ANTICIPATED DIVIDEND INCREASE
Given that the Assets generate a high percentage of FCF and are very sustainable in nature (with a low annual decline of 12 percent), Surge anticipates increasing the Company’s annual base cash dividend by 14 percent, from $0.42 per share to $0.48 per share (paid monthly), following the Closing of the Acquisition. This upwardly revised base dividend is consistent with Phase 1 of the Company’s previously announced return of capital framework.
Any dividend increase will be subject to the approval of Surge's Board of Directors with consideration given to the business environment at the Closing of the Acquisition.
ACQUISITION DETAILS; TERM DEBT FINANCING; EQUITY FINANCING
The Closing of the Acquisition is expected to occur on or about December 19, 2022. The Net Purchase Price payable by Surge at Closing is anticipated to be $200 million, and will be funded by way of the following:
1) $38 million of net proceeds from the bought deal common equity financing referenced below;
2) $100 million in amortizing term loans from existing first lien and second lien lenders;
3) $27 million draw on the Company’s existing first lien credit facility (which is expected to be drawn only $50 million at Closing, with over $100 million of undrawn, available capacity); and
4) $35 million in share consideration to Enerplus, from the issuance of Common Shares of SGY at a price equal to the bought deal common equity financing referenced below.
Concurrent with Closing, the Company expects to expand its syndicated first lien credit facility to a total of $210 million. This will be comprised of a $60 million term loan due November 2023, and a $150 million revolving credit facility. Additionally, the Company anticipates drawing a further $40 million on its existing second lien term facility to partially fund the Acquisition. This incremental second lien term debt is expected to be due November, 2024.
In conjunction with the Acquisition, Surge has entered into an agreement with a syndicate of underwriters led by National Bank Financial Inc. and Peters & Co. Limited (the "Underwriters"), pursuant to which the Underwriters have agreed to purchase, for resale to the public, on a bought-deal basis, approximately 4,325,000 Common Shares of Surge at a price of $9.25 per Common Share for gross proceeds of approximately $40 million (the "Offering"). The net proceeds from the Offering will be used to partially fund the Acquisition. The Underwriters will have an option to purchase up to an additional 15 percent of the Common Shares issued under the Offering (the “Over-Allotment”) on the same terms as the Offering to cover over-allotments exercisable in whole or in part at any time until 30 days after the closing.
The Common Shares issued pursuant to the Offering will be distributed by way of a short form prospectus in all provinces of Canada (excluding Québec) and may also be placed privately in the United States to Qualified Institutional Buyers (as defined under Rule 144A under the United States Securities Act of 1933, as amended pursuant to an exemption under Rule 144A, and may be distributed outside Canada and the United States on a basis which does not require the qualification or registration of any of the Company's securities under domestic or foreign securities laws. Completion of the Offering is subject to customary closing conditions, including the receipt of all necessary regulatory approvals, including the approval of the Toronto Stock Exchange. Closing of the Offering is expected to occur on November 22, 2022. Closing of the Offering is not conditional upon completion of the Acquisition. In the event the Acquisition is not completed, Surge may use the net proceeds of the Offering to reduce indebtedness, fund future acquisitions and for general corporate purposes. Prior to the closing of the Acquisition, the net proceeds may, from time to time, be invested in interest bearing deposits or in short-term interest bearing or discount debt obligations or other short-term investments (in each case, either Canadian or U.S. dollars).
Upon the Closing of the Acquisition, Surge will have an estimated 92.1 million Common Shares issued and outstanding inclusive of Common Shares issued in the Offering.
2023 OUTLOOK - STRONG OPERATIONAL PERFORMANCE DRIVING FREE CASH FLOW
The Acquisition further concentrates the Company’s focus within its Sparky and SE Saskatchewan core operating areas and is consistent with its return of capital business model. Surge will continue its disciplined development of the Company’s high quality, low cost, conventional crude oil asset base, including Surge’s premier Sparky play in Alberta, as well as its high operating netback, light oil assets in SE Saskatchewan. The addition of the acquired Assets further positions Surge to provide shareholders with sustainable free cash flow generation in 2023 and beyond.
Following the Acquisition, Surge will possess the following key operational and financial attributes:
- Over 3.1 billion barrels of net, internally estimated, conventional OOIP - with a low recovery factor to date of 7.5 percent;
- Combined Proven plus Probable year end 2021 independently evaluated reserves of more than 115 million boe;
- Average 2023 production estimated at more than 25,000 boepd (87 percent liquids weighted);
- A low base corporate decline of 23 percent;
- A large development drilling inventory of more than 1,000 net internally estimated locations4; providing a development drilling inventory of more than 12 years;
- A 12.5 year reserve life index (Total Proved plus Probable);
- Forecast cash flow from operating activities in 2023 of $360 million at US$80 WTI per bbl flat pricing;
- Forecasted FCF prior to dividends of over $170 million in 2023 at US$80 WTI per bbl flat pricing; and
- A large tax base with more than $1.5 billion of tax pools as of December 31, 2021.
Peters & Co. Limited and National Bank Financial Inc. acted as financial advisors to Surge with respect to the Acquisition. ATB Capital Markets has been appointed as strategic advisors to Surge on the Acquisition. McCarthy Tétrault LLP is acting as legal advisor to Surge with respect to the Acquisition and the Offering.
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 assumptions concerning the anticipated benefits of the Acquisition and the transaction metrics related thereto; the anticipated use of the net proceeds from the Offering; the timing of various matters in connection with the Acquisition and the Offering and the conditions to completion of each, as applicable; the market value of the consideration to be received by Enerplus in connection with the Acquisition; the operational performance of the Company following completion of the Acquisition; the approval of the dividend increase by Surge's Board of Directors; and Surge’s revised guidance for the remainder of 2022 and preliminary guidance for 2023.
The forward-looking statements are based on certain key expectations and assumptions made by Surge, including the Acquisition and Offering being completed on the timelines and on the terms currently anticipated; all necessary regulatory approvals being obtained on the timelines and in the manner currently anticipated; the business and operations of both the Company and the Assets, including that the Assets will continue to operate and produce in a manner consistent with past results; the anticipated benefits of the Acquisition and the Assets acquired in connection therewith; the expansion of the Company's syndicated first lien credit facility and any consents or approvals required in connection therewith; expectations and assumptions around the performance of existing wells and success obtained in drilling new wells; anticipated expenses, cash flow and capital expenditures; the application of regulatory and royalty regimes; prevailing commodity prices and economic conditions; development and completion activities; the performance of new wells; the successful implementation of waterflood programs; the availability of and performance of facilities and pipelines; the geological characteristics of Surge’s properties and the Assets; 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, the risks associated with the Acquisition and Offering, including timing of closing, if closing is completed, that the benefits thereof will not be as anticipated, the conditions to closing are not satisfied or waived and receipt of any regulatory approvals; 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 Annual Information Form dated March 9, 2022 and in Surge’s Management Discussion & Analysis for the year ended December 31, 2021, 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:
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, 2022.
Recovery factor is calculated by dividing the total amount of produced barrels of oil from a particular reservoir at a certain date by the original oil in place in the reservoir.
After giving effect to the Acquisition, the Company will have 2021YE TPP reserves of 120.4 mmboe. The reserves associated with the Acquisition have been evaluated by McDaniel & Associates Consultants Ltd. (“McDaniel”) for 2021YE (vs. Surge’s 2021YE reserves evaluated by Sproule).
Surge’s total internal OOIP estimate of Cadogan (Lloyd + SPKY), Freda Lake & Neptune (Ratcliff) and Giltedge (Lloyd) is 389 mmbbls, which has a CUM to Sept 2021 of 55.4 mmbbls (i.e. 14.2 percent recovery factor to date).
Surge’s evaluation of the Acquisition assets generates a 12 percent decline as of Jan 2022 (on 4,080 boe/d). McDaniel’s PDP decline is 14 percent and Proved plus PDP decline is 12 percent.
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 that 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 the Acquisition’s inventory supports ~60 gross (>45 net) internally estimated drilling locations. The Acquisition’s 2021 Year End reserves has 13.0 net booked locations (no SPKY locations booked). Of the 13 booked, 9.0 net are Proved locations and 4.0 net are Probable locations based on McDaniel’s evaluation. Assuming an average number of net wells drilled per year of 6.0, the Acquisition has more than 45 net locations, providing approximately 7 years of drilling.
Assuming a January 1, 2022 reference date, and after taking into account the Acquisition, the Company will have over >1,125 gross (>1,025 net) drilling locations identified herein, of these >600 gross (>550 net) are unbooked locations. Of the 469 net booked locations identified herein, 371 net are Proved locations and 99 net are Probable locations based on Sproule’s 2021YE reserves. Assuming an average number of net wells drilled per year of 80, Surge’s >1,025 net locations provide over 12 years of drilling.
Assuming a January 1, 2022 reference date, and after taking into account the Acquisition, the Company’s Sparky core area will have >450 net locations (165 net booked), 121 net are Proved locations and 44 net are Probable locations based on 2021YE reserves. Assuming an average number of net SPKY Core wells drilled per year of 40, Surge’s >450 net locations provide approximately 11 years of drilling.
Surge’s internally developed type curves (for both Surge and the Acquisition assets) were constructed using a representative, factual and balanced analog data set, as of January 1, 2022 for Surge type curves and the Acquisition type curves. All locations were risked appropriately, and estimated ultimate recoveries 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 and Other Financial Measures
Certain secondary financial measures in this press release – including, “free cash flow”, “operating netback”, “all-in payout ratio” and “net operating expenses” are not prescribed by GAAP. These specified financial measures include non-GAAP financial measures and non-GAAP ratios, are not defined by IFRS and therefore are referred to as non-GAAP and other financial measures. These non-GAAP and other financial measures are included because management uses the information to analyze business performance, cash flow generated from the business, leverage and liquidity, resulting from the Company’s principal business activities and it may be useful to investors on the same basis. None of these measures are used to enhance the Company’s reported financial performance or position. The non-GAAP and other financial measures do not have a standardized meaning prescribed by IFRS and therefore are unlikely to be comparable to similar measures presented by other issuers. They are common in the reports of other companies but may differ by definition and application. All non-GAAP and other financial measures used in this document are defined below:
Free Cash Flow
Free cash flow is a non-GAAP financial measure, calculated as cash flow from operating activities, before changes in non-cash working capital, less expenditures on property, plant, equipment. 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 a non-GAAP ratio, calculated using the same weighted average basic and diluted shares used in calculating income per share.
Operating netback is a non-GAAP financial measure, calculated as petroleum and natural gas revenue and processing and other income, less royalties, realized gain (loss) on commodity and FX contracts, operating expenses, and transportation expenses. Operating netback per boe is a non-GAAP ratio, calculated as operating netback divided by total barrels of oil equivalent produced during a specific period of time. There is no comparable measure in accordance with IFRS. This metric is used by management to evaluate the Company’s ability to generate cash margin on a unit of production basis.
All-in payout ratio
All-in payout ratio is a non-GAAP ratio, calculated as exploration and development expenditures, plus dividends paid, divided by cash flow from operations. This capital management measure is used by management to analyze allocated capital in comparison to the cash being generated by the principal business activities.
Net Operating Expenses
Net operating expenses is a non-GAAP financial measure, 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 when analyzed by management.
Additional information relating to non-IFRS measures can be found in the Company's most recent Management Discussion and Analysis, which may be accessed through the SEDAR website (www.sedar.com).
For more information about Surge, visit our website at www.surgeenergy.ca
|Paul Colborne, President & CEO||Jared Ducs, CFO|
|Surge Energy Inc.||Surge Energy Inc.|
|Phone: (403) 930-1507||Phone: (403) 930-1046|
|Fax: (403) 930-1011||Fax: (403) 930-1011|
|Email: email@example.com||Email: firstname.lastname@example.org|
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.
For more information about Surge, visit our website at www.surgeenergy.ca
1 This is a non-GAAP and other financial measure which is defined in the Non-GAAP and Other Financial Measures section of this document
2 Based on the following pricing assumptions: US$80.00WTI/bbl; CAD$109.59WTI/bbl; EDM CAD$104.11/bbl; WCS CAD $85.62/bbl; AECO CAD$5/mcf.
3 See the Oil and Gas Advisories section of this document.
4 See the Drilling Inventory section of this document.