News Releases

Surge Energy Inc. Announces 2019 First Quarter Results; Record Production

CALGARY, May 6, 2019 /CNW/ - Surge Energy Inc. ("Surge" or the "Company") (TSX: SGY) is pleased to announce its operating and financial results for the quarter ended March 31, 2019.


Q1/19 was a solid "recovery" quarter for Surge, as the extremely weak Q4/18 Canadian crude oil pricing fundamentals quickly turned positive during the period. With crude oil prices averaging US $54.90 per bbl, Surge's cash flow from operating activities increased eight percent as compared to Q4/18, and adjusted funds flow1 in Q1/19 increased by 570 percent to $41.9 million, as compared to Q4/18 at $6.2 million.

In Q1/19 Surge delivered record quarterly average production of 21,630 boepd (84% liquids), an increase of 35 percent over Q1/18 production of 16,027 boepd (81% liquids).

Operationally, Surge had a successful capital program in Q1/19, drilling and completing wells in all four core areas, namely Sparky, Valhalla, Greater Sawn, and Shaunavon. Surge added over 2,800 boepd (>90% liquids) in the quarter on total exploration and development expenditures of $41.3 million, resulting in excellent capital efficiencies2 of $14,750 per flowing boepd on an IP603 basis.  

Over the last 11 financial quarters Surge has now grown its quarterly production 78 percent, from 12,182 boepd (78% liquids) in Q2/16 to 21,630 boepd (84% liquids) in Q1/19. This consistent quarterly production growth has been achieved by adding predominantly high netback, light oil.

During Q1/19 Surge announced that the Company had increased its proven plus probable ("P+P") reserves by 29 percent, from 95.2 MMboe at year-end 2017, to 122.6 MMboe at year-end 2018. Surge also announced during the first quarter that the Company organically replaced 133 percent of 2018 production.

Furthermore, as compared to Q1/19, today Surge has additional upward leverage in its adjusted funds flow, with Q2/19 crude oil prices now trading over US$61 WTI per barrel, and Canadian WCS differentials narrowing below long term averages, at US$12 per barrel. At present crude pricing levels, the Company is generating meaningful free adjusted funds flow1.

The Company continues to focus on sustainability, balance sheet management, and cost controls to deliver returns to Surge shareholders. The Company also continues to grow its production base and 14 year drilling inventory in its four core areas at Sparky, Valhalla, Greater Sawn and Shaunavon – through low risk development drilling, waterfloods, and strategic, high quality, large OOIP4, core area acquisitions.



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


Capital efficiencies is calculated as total exploration and development expenditures during the period divided by an initial production ("IP") rate for a specified number of days (ie. 60 days).


See the Production Rates section of this document for further details.


See Reserves Data in the Forward-Looking Statement section of this document for further details.  



  • Surge's Q1/19 quarterly average production of 21,630 boepd (84% liquids) increased by 35 percent over Q1/18 average production of 16,027 boepd (81% liquids).
  • Cash flow from operating activities in Q1/19 was $28.9 million, an increase of 19 percent as compared to Q1/18 at $24.2 million.
  • Adjusted funds flow in Q1/19 was $41.9 million, an increase of 49 percent as compared to Q1/18 at $28.2 million.
  • Crude oil and liquids production increased by 40 percent - from 13,006 barrels per day in Q1/18 to 18,186 barrels per day in Q1/19.
  • The Company's operating netback5 increased by 12 percent, to $27.12 per boe in Q1/19, from $24.18 per boe in Q1/18.
  • The Company's December 31, 2018 net asset value ("NAV")6 is $5.58 per common share for Proven plus Probable ("P+P") reserves ($3.20 per share for Total Proved ("TP") reserves), based on the Company's independently evaluated Sproule reserve report (based on NPV10 before tax).
  • On March 28, 2019 Surge closed the disposition of certain non-core assets for cash proceeds of $28.1 million.



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

6 See Net Asset Value in the Forward-Looking Statement section of this document for further details.




Three Months Ended March 31,

($000s except per share amounts)



% Change

Financial highlights


Oil sales



41 %

NGL sales




Natural gas sales



223 %

Total oil, natural gas, and NGL revenue



43 %

Cash flow from operating activities



19 %

Per share - basic ($)




Adjusted funds flow



49 %

Per share - basic ($)1



17 %

Total exploration and development expenditures



18 %

Total acquisition and dispositions



329 %

Total capital expenditures




Net debt1, end of period



73 %


Operating highlights




Oil (bbls per day)



41 %

NGLs (bbls per day)



15 %

Natural gas (mcf per day)



14 %

Total (boe per day) (6:1)



35 %

Average realized price (excluding hedges):


Oil ($ per bbl)



0 %

NGL ($ per bbl)




Natural gas ($ per mcf)



183 %


Netback ($ per boe)


Petroleum and natural gas revenue



6 %

Realized gain (loss) on financial contracts








Net operating expenses1



4 %

Transportation expenses



57 %

Operating netback



12 %

G&A expense




Interest expense



57 %

Adjusted funds flow1



10 %


Common shares outstanding, end of period



36 %

Weighted average basic shares outstanding



33 %

Stock option dilution


Weighted average diluted shares outstanding



33 %

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

2 IFRS 16 was adopted January 1, 2019 using the modified retrospective approach and as such, comparative information for 2018 that may have been impacted has not been restated. Refer to the Changes in Accounting Policies section of the MD&A for additional information.


In accordance with industry practice, the Company uses adjusted funds flow to analyze the cash flow generated from its ongoing principal business activities. On this basis, both adjusted funds flow and cash flow from operating activities are provided for comparative purposes.  Please see the Non-GAAP Financial Measures section of this release for further details.


In Q1/19, Surge successfully drilled 12 gross (11.6 net) wells and completed a total of 18 gross (17.6 net) wells, adding over 2,800 boepd (>90% liquids) for a cost of $41.3 million ($14,750 per flowing boepd on an IP60 basis).

These results are a continuation of the operational momentum Surge has generated over the last 11 financial quarters - growing production by 78 percent from 12,182 boepd (78% liquids) in Q2/16, to 21,630 boepd (84% liquids) in Q1/19.

Throughout Q1/19 Surge operated three drilling rigs, drilling and completing wells in the Sparky, Valhalla, and Greater Sawn core areas, as well as, completing four previously drilled wells at the Company's Shaunavon core area. Each of the Company's four core areas are comprised of high quality, conventional, large OOIP per section, light and medium gravity crude oil reservoirs with large, consistent, scalable drilling inventories.

Sparky Core Area

In Q1/19, Surge drilled and completed 8 gross (7.6 net) wells in its Sparky core area at Sounding Lake, Eyehill, and Betty Lake.

At Sounding Lake, Surge drilled 2 gross (2.0 net) horizontal wells into its 25 million barrel net estimated OOIP Sparky MM pool, following up on the success of the first horizontal infill well drilled into the pool in Q4/18.  These two new wells were producing at rates of 180 bopd and 130 bopd respectively, during the last week of March. With 3 horizontal wells now placed into this previously vertically-developed pool, Surge estimates there are over 15 net additional horizontal drilling locations7 within the pool, at 400 meter spacing.

At Eyehill, 3 gross (2.6 net) Sparky wells were drilled, of which 2 gross (1.6 net) wells were drilled at 200m spacing, and continue to perform as per management's expectations. The third well (1.0 net), was successfully drilled offsetting existing horizontal water injection, which is expected to provide pressure support to the well. Surge has now drilled over 60 wells into its Eyehill Sparky pool and successfully implemented waterflood with the conversion of 7 wells to water injection. The Eyehill property has become a cornerstone of the Company's Sparky core area, with over 170 million barrels of estimated net OOIP, 56 producing horizontal wells, and 7 horizontal water injection wells placed in the pool in the last 5 years. Surge plans to continue to systematically develop and waterflood the pool with more than 65 net locations7 remaining to be drilled.

At Betty Lake, Surge continued operations drilling 3 gross (3.0 net) wells from a single pad. These 3 wells continued to produce at a combined rate of over 400 bopd for the last week of March. Surge now has 8 successful horizontal wells on production at its Betty Lake property. The Company plans to continue development, with more than 80 million barrels of estimated net OOIP, and more than 50 net drilling locations7 remaining.

For the remainder of 2019, Surge has budgeted 21 additional horizontal wells to be drilled in the Sparky core area, focusing its drilling at Provost, Eyehill and Betty Lake.


7 See the Drilling Locations section of this document for further details.  


Valhalla Core Area

At Valhalla, development drilling entered its 9th consecutive year. In Q1/19, Surge successfully drilled and completed 2 gross (2.0 net) horizontal wells into the Company's Doig light oil pool which has an estimated 150 million net barrels of OOIP. The two wells had an average 30-day initial production oil rate of over 1,000 bopd each, and were drilled more than 16 km apart, at opposite ends of the large Doig oil fairway. 

Surge has budgeted 3 gross (3.0 net) additional wells in the Valhalla area for the remainder of 2019.

Greater Sawn Core Area

In Q1/19, Surge drilled 2 gross (2.0 net) wells, and completed a total of 4 gross (4.0 net) wells at the Company's newly acquired, large OOIP, light oil assets in the Greater Sawn core area. All four of the wells were drilled using existing well control and 3D seismic, targeting the Slave Point reef facies in the Sawn oil pool with 100 percent success. The four wells were completed with an average of 28 frac stages and had combined production of over 820 bopd in the last week of March.

Surge plans to drill 5 gross (5.0 net) additional wells in 2H/19.

Shaunavon Core Area

In Q1/19, Surge completed 4 gross (4.0 net) wells in its Shaunavon core area, where production receives Fosterton pricing, which has historically traded at a premium to WCS. Three of the four wells targeted the Upper Shaunavon sandstone, with the remaining well placed in the Lower Shaunavon carbonate. The wells were drilled near the end of Q4/18, with completion operations commencing in early Q1/19.

Surge plans to drill 8 gross (8.0 net) additional wells in 2H/19.

Consistent Quarterly Production Growth

Based on continued positive drilling results, operational execution, and key core area acquisitions, Surge has consistently grown its quarterly production over the previous 11 financial quarters. The Company has now delivered six upward revisions to production guidance since Q2/16 - twice organically, and four times through accretive, core area, light and medium gravity crude oil acquisitions.

78% Production Growth Since Q2 2016 (CNW Group/Surge Energy Inc.)

Ongoing Sustainability Program

During Q1/19 Surge determined that, in addition to its ongoing, proactive, annual abandonment and reclamation program, the Company would elect to participate in the Alberta Energy Regulator's ("AER") Area Based Closure program ("ABC program"). 

Over the past 5 years, Surge has directed $17 million towards the abandonment and reclamation of inactive wells, abandoning over 475 wells in that time.  The Company believes participation in the ABC program will further allow Surge to optimize cost efficiencies as they relate to abandonments and reclamation.

On this basis, Surge will complete its first abandonment project under the ABC program in the first half of 2019, abandoning the Company's inactive Cherry natural gas property for approximately 55 percent of the deemed liability recorded by the AER.  This confirms the Company's belief that there are significant economies of scale to be achieved under the ABC program.

Surge remains committed to a proactive, well-funded annual abandonment and reclamation program.  The Company has budgeted $6 million for decommissioning expenditures in 2019, which is 45 percent more than required by the AER under the ABC program. Surge anticipates abandoning 125 wells in 2019.


On April 17, 2019 Surge entered into a $30 million bought-deal financing (the "Convertible Debenture Financing") of five-year convertible unsecured subordinated debentures (the "Debentures") at a price of $1,000 per Debenture, with a syndicate of underwriters led by National Bank Financial Inc. The Debentures have a coupon of 6.75 percent per annum, and a conversion price of $2.25 per Surge common share – which represents a 40 percent premium to Surge's share price on the day the Convertible Debenture Financing was announced.

The net proceeds from the Convertible Debenture Financing will be used to pay down a portion of the outstanding bank indebtedness under the Company's revolving term credit facility.

The closing of the Convertible Debenture Financing is set for on or about May 8, 2019.


The Company has been active with its ongoing crude oil and WCS differential hedging strategy designed to protect the capital program and Surge's annual dividend.

For 2H/19, the Company has hedged 6,250 bbl/d of WTI crude oil with an average floor price of CAD $77/bbl. This represents approximately 40 percent of Surge's forecasted after royalty crude oil production for 2H/19. Surge has also retained upside to further WTI price increases on 60 percent of the hedged volumes, with an average ceiling of CAD $103/bbl.

Furthermore, Surge has hedged 4,800 bbl/d of WCS basis differential for Q2/19 and Q3/19. This represents approximately 60 percent of the Company's forecasted net after royalty WCS corelated crude oil production. Of the 4,800 bbl/d of WCS basis differentials hedged, 55 percent are swapped at a US$16.40/bbl discount to WTI, and the remaining 45 percent are collared at an average discount to WTI of US$15.15 - $20.20/bbl.


Management's stated goal is to be the best positioned, top performing, light/medium gravity crude oil growth and dividend paying public oil company in our peer group in Canada.

Today, Surge has the following key operational and financial attributes:

Large Net OOIP1:

2.5 Billion barrels (6.2% cum to date recovery factor)


123 million boe P+P (Sproule Dec 31/18)

High Netback, Oil Weighted Production (liquids weighting):

22,000 boepd (85% light/medium oil + NGL's)

Low Corporate Decline:

23% per year

Long Reserve Life Index2:

15 years

Large Drilling Inventory1:

14 years (>770 net locations @ 55 wells per year)

Net Asset Value (Sproule Dec 31/18):

$3.20 per share TP; $5.58 per share P+P

2019e Exploration and Development Capital:

$135 million

Current Annual Dividend:

$31 million ($0.10 per share, per annum)

2019e Operating Costs3:

$14.95-$15.45 per boe

2019e Transportation Costs:

$1.50-$1.75 per boe

2019e General & Administrative Costs:

$1.75-$1.90 per boe



OOIP and locations in this table are net of values attributable to the non-core disposition.



Reserve life index (RLI) is calculated by dividing the P+P Sproule reserves at December 31, 2018 by 22,000 boepd annualized.



 Operating cost guidance includes adjustments for the impact of the adoption of IFRS 16.


Management believes that the operational and financial corporate fundamentals set forth above will allow Surge to continue to be a top performing, light and medium gravity crude oil growth and dividend paying Company for the foreseeable future. 

Surge's disciplined growth and dividend paying business strategy is set forth in the Company's detailed five-year growth plan8 as follows:

  • Grow production per share at five to six percent annually;
  • Maintain and grow the Company's dividend (current yield ~6.8%9); and
  • Deliver free adjusted funds flow annually of four to five percent.


Management's goal is to provide these annual returns on a consistent basis, along with an increasing, compounding dividend.


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, including its drilling and enhanced recovery plans; Surge's declared focus and primary goals; Surge's dividend policy and sustainability thereof; participation in the ABC program and the anticipated benefits therefrom; Surge's plans to abandon its inactive Cherry natural gas well and the timing thereof, Surge's abandonment and reclamation program and budget; the Convertible Debenture Financing, the terms and timing and anticipated use of proceeds thereof; Surge's hedging program; Surge's decline rates, reserve life index, drilling locations, OOIP, estimated 2019 exploration and development capital budget, estimated 2019 net operating, G&A and transportation costs; and the anticipated benefits of Surge's operational and financial corporate fundamentals.  

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 ability of Surge to increase its dividend; 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 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 or 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 14, 2019 and in Surge's MD&A for the period ended December 31, 2018, both of which have been filed on SEDAR and can be accessed at

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.


8 Additional details of the Company's five year growth plan can be found in the corporate presentation at

Based on a $1.46 share price and a $0.10 annual dividend per share.


Reserves Data

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 means barrel of oil equivalent per day. Bbl means barrel of oil. NGLs means natural gas liquids.

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.

Drilling Locations

This press release discloses drilling locations in two categories: (i) booked locations; and (ii) unbooked locations. Booked locations are proved locations and probable locations evaluated by Sproule. Unbooked locations are generated internally by Qualified Reserve Evaluators using standard practices as prescribed in the Canadian Oil and Gas Evaluations Handbook.

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 the December 31, 2018 reference date as noted per the Sproule Reserves report and excluding locations associated with the non-core disposition date March 28, 2019, Surge has over 770 net drilling locations identified herein, of which over 382 are unbooked locations and 389 net are booked locations. Of the 389 net booked locations identified herein, 297 net are Proved locations and 91 net are Probable locations. The Company's Sparky core area has 136 net booked locations, of which 100 net are Proved locations and 36 net are Probable locations. Betty Lake locations identified herein has 12 net booked Proved locations and 3 net booked Probable locations. Eyehill locations identified herein has 20 net booked Proved locations and 15 net booked Probable locations. Sounding Lake Sparky MM Pool locations identified herein has 5 net booked Proved locations and 4 net booked Probable locations.

Production Rates

References to initial production ("IP") rates found in this press release are useful for determining the presence of hydrocarbons. There is no assurance as to the length of time that wells will produce at such rates, and consideration must be given to natural declines thereafter.  As such, readers are cautioned when using these production rates to aggregate Surge's production.

Net Asset Value

The Company calculated its 2018 Net Asset Value as follows:




Reserve Value NPV10 BT ($MM) (1)



Undeveloped Land and Seismic ($MM) (2)



Net Debt ($MM)



Total Net Assets ($MM)



Basic Shares Outstanding (MM)



Fully Diluted Shares Outstanding (MM)



Estimated NAV per Basic Share ($/share)





Includes $148 MM (TP) and $165 MM (TPP) of costs for changes due to the COGE Handbook to include operating expenditures for non-producing properties and abandonment liabilities.


Internally estimated as $101 MM for non-reserve assigned land and $33 MM for seismic data.


Non-GAAP Financial Measures

Certain secondary financial measures in this press release – namely, "adjusted funds flow", "adjusted funds flow per share", "free adjusted funds flow", "net debt", "net operating expenses", "operating netback" and "adjusted funds flow per boe" are not prescribed by GAAP. These non-GAAP financial measures are included because management uses the information to analyze business performance, cash flow generated from the business, leverage and liquidity, resulting from the Company's principal business activities and it may be useful to investors on the same basis. None of these measures are used to enhance the Company's reported financial performance or position. The non-GAAP measures do not have a standardized meaning prescribed by IFRS and therefore are unlikely to be comparable to similar measures presented by other issuers. They are common in the reports of other companies but may differ by definition and application. All non-GAAP financial measures used in this document are defined below:

Adjusted Funds Flow & Adjusted Funds Flow per Share

The Company adjusts cash flow from operating activities in calculating adjusted funds flow for changes in non-cash working capital, decommissioning expenditures, transaction and other costs, and cash settled stock-based compensation plans, particularly cash used to settle withholding obligations on stock-based compensation arrangements that are settled in shares. 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, which management believes do not reflect the ongoing cash flows of the business, and as such reduces comparability. Subsequent to the third quarter of 2018, all of the Company's stock-based compensation plans are equity classified as the Company has the intention of settling all awards with shares. Cash settled stock-based compensation currently represents the statutory tax withholdings required on stock-based compensation awards and is a discretionary allocation of capital. The Company has the option to either require the holder to sell shares earned in the stock-based compensation plan to satisfy tax withholdings, or the Company can issue less shares to the individual and remit a cash payment to satisfy tax withholding requirements. 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 months and year ended March 31, 2019:


Three Months Ended

($000s except per share)

Mar 31, 2019


Mar 31, 2018

Cash flow from operating activities






Change in non-cash working capital




Decommissioning expenditures




Transaction and other costs




Adjusted funds flow






Per share – basic







Free Adjusted Funds Flow

Free adjusted funds flow is calculated as adjusted funds flow less the sum of total exploration and development capital and dividends and represents, in dollars, the excess of adjusted funds flows above exploration and development capital and dividends. Management uses this measure to assess whether adjusted funds flow is sufficient to fund the ongoing capital requirements of the Company whilst servicing the dividend.

Net Debt

There is no comparable measure in accordance with IFRS for net debt. Net debt is calculated as bank debt plus the liability component of the convertible debentures plus or minus working capital, however, excluding the fair value of financial contracts, finance lease obligations and other long term liabilities. This metric is used by management to analyze the level of debt in the Company including the impact of working capital, which varies with timing of settlement of these balances.



As at March 31,

As at December 31,

As at March 31,

Bank debt

$ (398,666)

$ (408,593)

$ (222,353)

Accounts receivable




Prepaid expenses and deposits




Accounts payable and accrued liabilities




Convertible debentures - liability portion




Dividends payable





$ (438,150)

$ (461,187)

$ (252,742)



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 in the MD&A.

Operating Netback & Adjusted Funds Flow per boe

Operating netback & adjusted funds flow per boe for the three months ended March 31, 2019 are calculated on a per unit basis as follows:


Three Months Ended

($000s except per share)


Mar 31, 2019


Mar 31, 2018

Petroleum and natural gas revenue*







Processing and other income*










Operating expenses*





Transportation expenses*





Realized gain (loss) on financial contracts*





Operating netback







G&A expense*





Interest expense*





Adjusted funds flow







Barrels of oil equivalent (boe)





Operating netback ($ per boe)







Adjusted funds flow ($ per boe)








* Taken directly from the financial statements.


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 (

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.

Surge Energy Inc. (CNW Group/Surge Energy Inc.)

SOURCE Surge Energy Inc.

For further information: Paul Colborne, President & CEO, Surge Energy Inc., Phone: (403) 930-1507, Fax: (403) 930-1011, Email:; Jared Ducs, Vice President Finance, Surge Energy Inc., Phone: (403) 930-1046, Fax: (403) 930-1011, Email: