Surge Energy Inc. Announces 2018 Fourth Quarter and Year-End Financial and Operating Results; 2018 Year-End Reserves; Record Production and Reserves Achieved

CALGARY, March 12, 2019 /CNW/ - Surge Energy Inc. ("Surge" or the "Company") (TSX: SGY) is pleased to announce its operating and financial results for the quarter ended December 31, 2018, and its year-end 2018 reserves, as evaluated by Sproule.

Surge's financial and operating results for the fourth quarter of 2018 include only a partial quarter of the previously announced Mount Bastion Oil & Gas Ltd. ("MBOG") light oil acquisition, which closed during the fourth quarter of 2018.

MESSAGE TO THE SHAREHOLDERS

Overall, 2018 was a transformative year for the Company. Surge's Q4 2018 production of 21,047 boepd (82% oil and NGLs) increased by more than 34 percent (over 8 percent per share) as compared to Q4 2017 production volumes of 15,675 boepd (81% oil and NGLs). This production growth was predominantly generated by the addition of high-netback, light oil production. Additionally, Surge 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.

Operationally, the Company's high quality, large original oil in place¹ ("OOIP"), conventional reservoirs continued to deliver consistent results. The Company organically replaced 133% of 2018 production, and has delivered three year FD&A costs of $12.77 per boe on a P+P basis. This drove a three year average recycle ratio of 2.5 times².

During the fourth quarter of 2018 the price of oil dropped 44% - from over US$76 WTI per barrel to as low as US$42.50 WTI per barrel.   Furthermore, Western Canadian Select ("WCS") crude oil differentials widened precipitously from US$19 per barrel to as high as US$50 per barrel, and Edmonton Light differentials widened from US$4 per barrel to more than US$30 per barrel. 

Surge management reacted quickly to these negative market conditions by reducing capital expenditures and delaying well completions into 2019. Accordingly, on January 14, 2019, Surge announced a 2019 capital expenditure budget which focused on sustainability, generation of free adjusted funds flow³ at lower commodity prices, and payment of the Company's dividend. 

The extremely negative factors that affected Q4 2018 financial results have corrected quickly in Q1 2019.  WTI crude oil prices are up approximately 35% since December 2018, and both Edmonton light and WCS crude oil differentials have quickly tightened to below historical averages.  Currently, Surge is receiving pricing on its WCS correlated production that is 675% higher than in December 2018, at C$62 per barrel, and Edmonton light production is receiving 275% higher pricing than December 2018, at C$70 per barrel.

Surge remains well-positioned to execute its 2019 guidance, focused on the continued development of its extensive portfolio of large OOIP, light and medium gravity crude oil assets. 

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¹ See Reserves Data in the Forward-Looking Statement section of this document for further details

² See the Performance Measures section of this document for further details

³ This is a non-GAAP financial measure which is defined in the Non-GAAP Financial Measures section of this document

FINANCIAL AND OPERATING HIGHLIGHTS
($000s except per share amounts)

	Three Months Ended December 31,				Year Ended December 31,
	2018	2017	% Change		2018	2017	% Change
Financial highlights
Oil sales	51,424	64,221	(20)%		285,378	217,194	31 %
NGL sales	2,477	2,751	(10)%		11,022	9,431	17 %
Natural gas sales	4,226	2,288	85 %		8,147	14,283	(43)%
Total oil, natural gas, and NGL revenue	58,127	69,260	(16)%		304,547	240,908	26 %
Cash flow from operating activities	26,770	28,640	(7)%		121,907	93,682	30 %
Per share - basic ($)	0.09	0.12	(25)%		0.50	0.41	22 %
Adjusted funds flow^1	6,249	32,173	(81)%		113,651	103,816	9 %
Per share - basic ($)^1	0.02	0.14	(86)%		0.46	0.45	2 %
Total exploration and development expenditures	33,598	22,709	48 %		120,552	98,466	22 %
Total acquisition and dispositions	299,032	368	nm^2		327,765	72,465	nm
Total capital expenditures	332,630	23,077	nm		448,317	170,931	162 %
Net debt^1, end of period	461,187	239,718	92 %		461,187	239,718	92 %
Operating highlights
Production:
Oil (bbls per day)	16,578	12,169	36 %		13,992	11,347	23 %
NGLs (bbls per day)	703	571	23 %		623	639	(3)%
Natural gas (mcf per day)	22,598	17,607	28 %		20,658	17,615	17 %
Total (boe per day) (6:1)	21,047	15,675	34 %		18,058	14,922	21 %
Average realized price (excluding hedges):
Oil ($ per bbl)	33.72	57.36	(41)%		55.88	52.44	7 %
NGL ($ per bbl)	38.28	52.41	(27)%		48.51	40.41	20 %
Natural gas ($ per mcf)	2.03	1.41	44 %		1.08	2.22	(51)%
Netback ($ per boe)
Petroleum and natural gas revenue	30.02	48.03	(37)%		46.21	44.23	4 %
Realized loss on financial contracts	(1.25)	(0.81)	54 %		(1.67)	(0.74)	126 %
Royalties	(3.86)	(5.62)	(31)%		(6.55)	(5.53)	18 %
Net operating expenses^1	(15.70)	(13.85)	13 %		(14.76)	(13.62)	8 %
Transportation expenses	(1.53)	(1.21)	26 %		(1.50)	(1.41)	6 %
Operating netback^1	7.68	26.54	(71)%		21.73	22.93	(5)%
G&A expense	(1.83)	(1.95)	(6)%		(2.01)	(1.94)	4 %
Interest expense	(2.60)	(2.28)	14 %		(2.47)	(1.94)	27 %
Adjusted funds flow^1	3.25	22.31	(85)%		17.25	19.05	(9)%
Common shares outstanding, end of period	309,286	232,989	33 %		309,286	232,989	33 %
Weighted average basic shares outstanding	288,744	232,929	24 %		246,252	228,212	8 %
Stock option dilution	—	—	—%		—	—	—%
Weighted average diluted shares outstanding	288,744	232,929	24 %		246,252	228,212	8 %

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

2 The Company views this change calculation as not meaningful, or "nm".

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.

2018 FOURTH QUARTER AND YEAR-END RESERVES HIGHLIGHTS

• During the fourth quarter, Surge announced the closing of the Company's accretive MBOG light oil acquisition, and the creation of the Greater Sawn core area;
  
  
• Surge's Q4/18 quarterly average production of 21,047 boepd increased by more than 34% as compared to Q4/17 production of 15,675 boepd;
  
  
• The Company's Q4/18 quarterly average production of 21,047 boepd increased by 17% as compared to Q3/18 production of 18,029 boepd;
  
  
• The Company's revolving credit facility increased by 57 percent to $550 million, up from $350 million previously. The Company had over $140 million in undrawn capacity⁴ at December 31, 2018;
  
  
• Independently engineered Proved Developed Producing reserves (as of December 31, 2018) of 43.4 MMboe, increased 31% from year-end 2017;
  
  
• Total Proved Plus Probable reserves of 122.6 MMboe, increased 29% from year-end 2017;
  
  
• Organically added 8.0 MMboe of Proved Plus Probable Reserves, replacing 133% of 2018 production⁵;
  
  
• Organically added 6.2 MMboe of Proved Developed Reserves, replacing 102% of 2018 production⁵;
  
  
• Total Proved Plus Probable FD&A⁷ cost of $20.97/boe including changes in future development capital;
  
  
• Delivered three year average Total Proved Plus Probable FD&A cost of $12.77/boe⁷, including changes in future development capital;
  
  
• Reported a three year average recycle ratio of 2.5 times on a Total Proved Plus Probable basis;
  
  
• Total Proved Plus Probable Reserve life index⁶ of 16 years;
  
  
• Estimated Total Proved Plus Probable Net Asset Value of $5.58 per common share⁷, a 1% increase from year-end 2017; and
  
  
• Estimated Total Proven Net Asset Value of $3.20 per common share⁷.
  
  
• Subsequent to Q4/18, Surge has executed a definitive purchase and sale agreement regarding the disposition of certain non-core assets for cash proceeds of $28.65 million, subject to standard closing adjustments.

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⁴ Calculated as $550 million, less reported bank debt of $408.6 million as per the December 31, 2018 Financial Statements of the Company

⁵ Production Replacement is calculated as the total organic reserves additions (ie. excluding acquisitions and dispositions) divided by annual production (excluding acquisitions and dispositions)

⁶ Reserve Life Index is calculated as total Company share reserves divided by the annualized fourth quarter actual production

⁷ See the Performance Measures section of this document for further details

2018 OPERATIONAL HIGHLIGHTS

Surge's disciplined operating strategy and high quality conventional, large OOIP assets continued to provide strong operational results in 2018. When combined with the MBOG light oil acquisition, this resulted in Surge achieving record production of 21,047 boepd in the fourth quarter of 2018. The Company has now increased production by 73% from Q2 2016 through Q4 2018.

In total, the Company spent $120.6 million of exploration and development capital in 2018, drilling 46 gross (45.6 net) wells, along with waterflood injector conversions, associated infrastructure, land and seismic. Through step-out delineation drilling and minor land acquisitions, the Company was able to increase the drilling inventory to over 800⁸ net internally estimated locations, representing an increase of over 20% from 2017. 

Sparky Core Area
In the Sparky core area, Surge drilled 25 gross (24.6 net) wells in four separate fields during the year. In addition to continued drilling at Eyehill and Provost, the Company drilled four additional wells and constructed a battery at Betty Lake. Peak production from the Betty Lake field was over 600 boepd, and three additional wells have now been drilled into the pool in Q1 2019. With over 50 net remaining internally estimated locations, this large OOIP Sparky asset is very well-positioned for long term, sustainable growth.

In the Sounding Lake field, the Company drilled its first Sparky horizontal infill well in Q4 2018. This well continues to produce at over 150 boepd. An additional two wells have been drilled in the Sounding Lake area in Q1 2019.

With drill, complete and equip costs of under $1.3 million, year-round access, well-developed infrastructure, proven waterflood performance and over 400 internally identified net locations, the Sparky core area is a cornerstone asset of Surge's business.

Valhalla Core Area
At Valhalla, Surge successfully drilled and completed 5 gross (5 net) wells in 2018. Four of these wells were drilled into the Doig formation and had an average 30 day initial production oil rate of over 1,100 bopd. Two Doig wells have been drilled in Q1 2019.

The Company also drilled its first well into the Charlie Lake formation with a 30 day IP oil rate over 200 bopd. Throughout 2018, Surge continued to expand its drilling inventory in this multi-zone area and now has over 85 net locations in the Doig, Montney, Doe Creek and Charlie Lake formations.

Shaunavon Core Area
Surge successfully drilled 14 gross (14 net) wells at its Shaunavon core area in the past year, targeting both the Upper and Lower Shaunavon formations. Production from the field was maintained throughout the year at approximately 2,500 boepd.

Strategically positioned in Southwest Saskatchewan, Shaunavon receives Fosteron grade crude oil pricing, which has historically traded at a premium to WCS. Accordingly, Shaunavon has one of the highest operating netbacks in the Company and generates free adjusted funds flow⁹ that can be deployed across Surge's asset base. 

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⁸ See the drilling locations section of this document for further details.

Greater Sawn Core Area
With the closing of the MBOG acquisition in Q4 2018, Surge created a fourth core operating area at Greater Sawn. The light oil, large OOIP, carbonate reef pools with waterflood potential complement Surge's existing asset base and business model. Shortly after closing the acquisition in 2018, the Company drilled 2 gross (2 net) wells at Sawn. An additional two net wells have been drilled in Q1 2019 and all four wells have now been placed on production.

In the Sawn pool, five horizontal wells have already been converted to water injection by the previous operator, and plans are underway to further expand the waterflood and convert another one to two wells to water injection in 2019. A comprehensive reservoir simulation is also being completed on the Sawn pool to optimize future infill drilling and waterflood development.

2018 YEAR-END RESERVES

The Company's reserves were evaluated by Sproule in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ("NI 51-101") effective December 31, 2018. Surge's annual information form for the year ended December 31, 2018 (the "AIF") will contain Surge's reserves data and other oil and natural gas information as mandated by NI 51-101. Surge expects to file the Company's AIF on SEDAR on or before March 31, 2019.

The following tables summarize Surge's working interest oil, natural gas liquids and natural gas reserves and the net present values ("NPV") of future net revenue for these reserves (before taxes) using forecast prices and costs as evaluated in the Sproule Report.  The evaluation is based on Sproule's forecast pricing and exchange rates at December 31, 2018 which is available on their website www.sproule.com. All references to reserves in this release are to gross Company reserves, meaning Surge's working interest reserves before deductions of royalties and before consideration of the Company's royalty interests. The amounts in the tables may not add due to rounding.

⁹ This is a non-GAAP financial measure which is defined in the Non-GAAP Financial Measures section of this document

RESERVES SUMMARY AND NET PRESENT VALUE

Gross Reserves^(1)		Crude Oil and NGLs (Mbbl)^(2)	Natural Gas (MMcf)^(3)	Oil Equivalent Total Reserves (Mboe)	Before Tax NPV of Future Net Revenue^(4) Discounted at
					5% ($MM)	10% ($MM)	15% ($MM)
Proved:
	Proved Producing	37,511	35,369	43,406	815	741	656
	Proved Non-Producing	1,631	989	1,796	49	39	33
	Proved Undeveloped	29,336	36,173	35,365	738	538	404
Total Proved		68,478	72,531	80,566	1,602	1,318	1,093
	Probable	36,392	34,111	42,077	1,060	736	548
Total Proved Plus Probable		104,869	106,643	122,643	2,662	2,054	1,641

(1)	Amounts may not add due to rounding.
(2)	Includes light, medium, heavy and tight oil and natural gas liquids.
(3)	Includes conventional natural gas, solution gas and coal bed methane.
(4)	Total ADR (Abandonment, Decommissioning, Reclamation) is included in the reserves report, as it is best practice stated in the COGE Handbook.

FUTURE CAPITAL COSTS

	Total Proved	Total Proved Plus Probable
	($MM)	($MM)
2019	113	127
2020	155	202
2021	166	192
2022	109	165
2023	64	107
Remaining	37	61
Total (Undiscounted)	644	854
Total (Discounted at 10%)	509	660

		(1)	In addition to Future Development Costs, Future Capital Costs include an additional $103 million of
			undiscounted maintenance capital ($54 MM discounted at 10%).

PERFORMANCE MEASURES

	2018		Three Year Average
	TP	TPP	TP	TPP
F&D ($/boe) ^(1)	$22.39	$22.99	$15.71	$19.84
FD&A ($/boe) ^(2)	$25.34	$20.97	$17.77	$12.77
FD&A Recycle Ratio ^(3)	0.92	1.12	1.28	2.49
Production Replacement (%) ^(4)	128%	133%	134%	131%
RLI (Years) ^(5)	10.5	16.0	10.8	16.9

(1)	2018 Finding and Development costs calculated using capital of $115 million plus changes in FDC of $69 million.
(2)	2018 Finding, Development and Acquisition costs calculated using capital of $448 million, plus total change in FDC of $265 million.
(3)	Recycle Ratio is calculated using the 2018 operating netback excluding realized gain (loss) on financial contracts^10 of $23.40/boe divided by F&D. The Company's 2018 operating netback includes only 2 months of contribution from the MBOG acquisition.
(4)	Production Replacement is calculated as the total organic reserves additions (ie. excluding acquisitions and dispositions) divided by annual production (excluding acquisitions and dispositions).
(5)	Reserve Life Index is calculated as total Company share reserves divided by the annualized fourth quarter actual production.

NET ASSET VALUE

	TP	TPP
Reserve Value NPV10 BT ($MM) ^(1)	1,318	2,054
Undeveloped Land and Seismic ($MM) ^(2)	134	134
Net Debt ($MM)	(461)	(461)
Total Net Assets ($MM)	990	1,726
Basic Shares Outstanding (MM)	309.3	309.3
Fully Diluted Shares Outstanding (MM)	318.5	318.5
Estimated NAV per Basic Share ($/share)	$3.20/sh	$5.58/sh

(1)	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.
(2)	Internally estimated as $101 MM for non-reserve assigned land and $33 MM for seismic data.

OUTLOOK

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

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¹⁰ This is a non-GAAP financial measure which is defined in the Non-GAAP Financial Measures section of this document.

Overall, 2018 was a transformative year for the Company. Surge's Q4 2018 production of 21,047 boepd (82% oil and NGLs) increased by more than 34 percent (over 8 percent per share) over Q4 2017 production volumes of 15,675 boepd (81% oil and NGLs). This significant production growth was predominantly generated by the addition of high-netback, light oil production. Additionally, Surge 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.

On January 14, 2019 Surge announced a 2019 capital budget of $135 million. This budget provides substantial flexibility to react to changing commodity prices, while allowing the Company to continue to deliver its sustainable dividend to shareholders.

The Company's 2019 capital budget is focused on the continued development of its extensive portfolio of low risk, large OOIP, light and medium gravity crude oil assets. Surge will execute this plan while maintaining the Company's low 23 percent corporate decline rate, and Surge's $140 million of credit availability¹¹.

Over the last ten financial quarters, Surge has continued to build and maintain the Company's track record, delivering:

1. consistent successful drilling and waterflood results;
2. timely and accretive core area acquisitions;
3. increased production by more than 73 percent; and
4. increased Surge's dividend three times by a cumulative 33 percent.

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 annual exploration and development capital expenditure program and budget and its flexibility to make adjustments thereto; commodity prices and management's ability to react to changes thereto; maintenance of Surge's decline rate; production curtailments; export pipelines; availability of undrawn capacity with respect to Surge's credit facility; Surge's dividend policy and sustainability thereof and anticipated timing of filing the Company's AIF.

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 post-closing; the availability and costs of capital, labour and services; and the creditworthiness of industry partners.

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¹¹ Calculated as $550 million, less reported bank debt of $408.6 million as per the December 31, 2018 Financial Statements of the Company.

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, 2018 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 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.

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, Surge has over 800 net drilling locations identified herein, of which over 400 are unbooked locations and 404 net are booked locations. Of the 404 net booked locations identified herein, 305 net are Proved locations and 99 net are Probable locations. The Company's Sparky core area has 133 net booked locations, of which 99 net are Proved locations and 34 net are Probable locations. Betty Lake locations identified herein has 12 net booked Proved locations and 3 net booked Probable locations. Valhalla locations identified herein has 46 net Proved locations and 16 net Probable locations. 

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", "operating netback excluding realized gain (loss) on financial contracts" 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 December 31, 2018:

	Three Months Ended					Years Ended
($000s except per share)	Dec 31, 2018			Dec 31, 2017		Dec 31, 2018			Dec 31, 2017
Cash flow from operating activities	$	26,770		$	28,640	$	121,907		$	93,682
Change in non-cash working capital	(25,464)			2,276		(24,338)			4,644
Decommissioning expenditures	1,439			829		6,348			2,457
Transaction and other costs	3,504			-		5,288			1,155
Cash settled stock-based compensation	-			428		4,447			1,878
Adjusted funds flow	$	6,249		$	32,173	$	113,651		$	103,816
Per share – basic	$	0.02		$	0.14	$	0.46		$	0.45

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 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.

($000s)	As at December 31, 2018		As at December 31, 2017
Bank debt	$ (408,593)		$ (209,231)
Accounts receivable	21,084		36,291
Prepaid expenses and deposits	9,222		2,889
Accounts payable and accrued liabilities	(42,350)		(31,107)
Dividends payable	(2,577)		(1,845)
Convertible debentures	(37,973)		(36,715)
Total	$ (461,187)		$ (239,718)

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, Operating Netback Excluding Realized Gain (Loss) on Financial Contracts, & Adjusted Funds Flow Netback

Operating netback, operating netback excluding realized gain (loss) on financial contracts & adjusted funds flow per boe for the three and twelve months ended December 31, 2018 are calculated on a per unit basis as follows:

	Three Months Ended					Years Ended
($000s except per share)	Dec 31, 2018			Dec 31, 2017		Dec 31, 2018			Dec 31, 2017			Dec 31, 2016
Petroleum and natural gas revenue*	$	58,127		$	69,260	$	304,547		$	240,908		$	165,568
Processing and other income*	576			502		2,818			2,502			1,993
Royalties*	(7,478)			(8,106)		(43,203)			(30,099)			(19,197)
Operating expenses*	(30,985)			(20,476)		(100,108)			(76,697)			(59,623)
Transportation expenses*	(2,971)			(1,740)		(9,878)			(7,670)			(7,302)
Operating netback excluding realized gain (loss) on financial contracts	$	17,269		$	39,440	$	154,176		$	128,944		$	81,439
Realized gain (loss) on financial contracts*	(2,430)			(1,163)		(11,007)			(4,013)			3,963
Operating netback	$	14,839		$	38,277	$	143,169		$	124,931		$	85,402
G&A expense*	(3,551)			(2,813)		(13,228)			(10,575)			(8,708)
Interest expense*	(5,039)			(3,291)		(16,289)			(10,540)			(6,468)
Adjusted funds flow	$	6,249		$	32,173	$	113,651		$	103,816		$	70,226
Barrels of oil equivalent (boe)	1,936,352			1,441,982		6,591,007			5,446,777			4,717,008
Operating netback excluding realized gain (loss) on financial contracts ($ per boe)	$	8.93		$	27.35	$	23.40		$	23.67		$	17.26
Operating netback ($ per boe)	$	7.68		$	26.54	$	21.73		$	22.93		$	18.10
Adjusted funds flow ($ per boe)	$	3.25		$	22.31	$	17.25		$	19.05		$	14.88
* 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 (www.sedar.com).

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.

Paul Colborne, President & CEO, Surge Energy Inc., Phone: [phone], Fax: [phone], Email: [email protected]; Jared Ducs, Vice President Finance, Surge Energy Inc., Phone: [phone], Fax: [phone], Email: [email protected]

Related Links

http://www.surgeenergy.ca