Surge Energy Inc. Announces Second Quarter Results; Appointment of CFO

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CALGARY, Aug. 12, 2019 /CNW/ - Surge Energy Inc. ("Surge" or the "Company") (TSX: SGY) is pleased to announce its financial and operating results for the quarter ended June 30, 2019.

MESSAGE TO THE SHAREHOLDERS

Surge Energy Inc. Announces Second Quarter Results; Appointment of CFO (CNW Group/Surge Energy Inc.)

Eyehill Production Growth greater than 380 Percent in 3 Years (CNW Group/Surge Energy Inc.)

Eyehill Production Profile (Low Decline Waterflood) (CNW Group/Surge Energy Inc.)

Q2/19 was an excellent quarter for Surge. Production and adjusted funds flow¹ came in higher than analyst estimates²; and the Company's bank debt, net debt¹, operating expenses, transportation expenses, and general and administrative costs all came in lower than budgeted expectations³.

Production of 21,544 boepd in Q2/19 averaged more than Surge's 2019 exit rate guidance of 21,500 boepd, which represents an increase of 26 percent over Q2/18 at 17,072 boepd.

Surge was originally guiding to exit 2019 with production of 22,000 boepd; however, the Company sold a 490 boepd non-core asset in Q1/19 for net cash proceeds of $28.1 million, resulting in new 2019 production exit rate guidance of 21,500 boepd.

Drilling results from Surge's Q2/19 program exceeded management's expectations. Successful drilling in Q2/19 at the Company's Sparky, Shaunavon and Valhalla core areas has resulted in current estimated production additions of 1,625 bopd, for total exploration and development expenditures of $25.2 million, providing capital efficiencies⁴ of approximately $15,877 per bopd.

HIGHLIGHTS

• Surge's Q2/19 quarterly production of 21,544 boepd increased by 26 percent over Q2/18 production of 17,072 boepd.
• Adjusted funds flow in Q2/19 was $50.7 million, an increase of 31 percent as compared to Q2/18 at $38.6 million.
• Cash flow from operating activities in Q2/19 was $45.8 million, an increase of 36 percent as compared to Q2/18 at $33.7 million.
• The Company's operating netback¹ increased by six percent, to $31.24 per boe in Q2/19, from $29.46 per boe in Q2/18.
• The Company's operating expenses for Q2/19 were $14.43 per boe and net operating expenses¹ were $14.03 per boe, compared to 2019 guidance of $14.95 - $15.45 per boe.
• The Company generated $17.7 million of adjusted funds flow¹ in the quarter in excess of exploration and development expenditures and dividends paid.
• Surge paid dividends of $7.9 million in Q2/19, representing 15 percent of Q2/19 adjusted funds flow.
• The Company maintained a net debt to annualized Q2/19 adjusted funds flow ratio¹ of under two times (1.9x).
• Surge closed a small, miscellaneous gross overriding royalty ("GORR") disposition of 214 boepd on June 28, 2019, for net cash proceeds of $29.1 million – providing sale metrics of greater than $135,000 per flowing boepd.
• Subsequent to June 30, 2019, pursuant to a Crown sale on July 31, 2019, Surge successfully acquired an additional 8.5 sections of highly prospective Sparky acreage at Betty Lake – extending the Company's large new Sparky discovery to the north.
• Subsequent to June 30, 2019, pursuant to a Crown sale on July 31, 2019, Surge successfully acquired an additional 9.5 sections of highly prospective acreage at Nipisi South in the Company's Greater Sawn core area. This new land is immediately offsetting existing Surge light oil production, and is prospective for both Slave Point and Clearwater oil reserves and production.

FINANCIAL AND OPERATING SUMMARY

		Three Months Ended June 30,				Six Months Ended June 30,
($1000s except per share amounts)		2019	2018*	% Change		2019	2018*	% Change
Financial highlights
Oil sales		104,387	83,516	25 %		195,515	148,008	32 %
NGL sales		1,649	2,486	(34)%		4,074	4,947	(18)%
Natural gas sales		1,629	1,092	49 %		5,944	2,429	145 %
Total oil, natural gas, and NGL revenue		107,665	87,094	24 %		205,533	155,384	32 %
Cash flow from operating activities		45,807	33,725	36 %		74,715	57,940	29 %
Per share - basic ($)		0.15	0.15	3 %		0.24	0.25	(4)%
Adjusted funds flow		50,742	38,596	31 %		92,593	66,765	39 %
Per share - basic ($)		0.16	0.17	(6)%		0.30	0.29	3 %
Total exploration and development expenditures		25,197	23,344	8 %		66,458	58,253	14 %
Total acquisition and dispositions		(29,166)	28,939	(201)%		(56,973)	22,454	(354)%
Total capital expenditures		(3,969)	52,283	(108)%		9,485	80,707	(88)%
Net debt, end of period		391,020	276,140	42 %		391,020	276,140	42 %
Operating highlights
Production:
Oil (bbls per day)		17,366	13,343	30 %		17,454	12,897	35 %
NGLs (bbls per day)		727	556	31 %		685	558	23 %
Natural gas (mcf per day)		20,706	19,038	9 %		20,685	18,585	11 %
Total (boe per day) (6:1)		21,544	17,072	26 %		21,587	16,553	30 %
Average realized price (excluding hedges):
Oil ($ per bbl)		66.05	68.78	(4)%		61.89	63.40	(2)%
NGL ($ per bbl)		24.93	49.15	(49)%		32.84	48.99	(33)%
Natural gas ($ per mcf)		0.86	0.63	37 %		1.59	0.72	121 %
Netback ($ per boe)
Petroleum and natural gas revenue		54.92	56.06	(2)%		52.60	51.86	1 %
Realized gain (loss) on financial contracts		(1.29)	(2.46)	(48)%		(0.83)	(1.81)	(54)%
Royalties		(7.03)	(8.36)	(16)%		(6.36)	(7.32)	(13)%
Net operating expenses		(14.03)	(14.16)	(1)%		(14.58)	(14.37)	1 %
Transportation expenses		(1.33)	(1.62)	(18)%		(1.66)	(1.45)	14 %
Operating netback		31.24	29.46	6 %		29.17	26.91	8 %
G&A expense		(1.86)	(2.06)	(10)%		(1.82)	(2.14)	(15)%
Interest expense		(3.48)	(2.56)	36 %		(3.66)	(2.50)	46 %
Adjusted funds flow		25.90	24.84	4 %		23.69	22.27	6 %
Common shares outstanding, end of period		314,051	230,494	36 %		314,051	230,494	36 %
Weighted average basic shares outstanding		314,010	230,812	36 %		311,742	231,904	34 %
Stock option dilution		—	5,265	(100)%		—	4,407	(100)%
Weighted average diluted shares outstanding		314,010	236,077	33 %		311,742	236,311	32 %

*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

OPERATIONAL HIGHLIGHTS 

In Q2/19, Surge successfully drilled 9 gross (9 net) producing wells, currently producing an estimated 1,625 bopd, for total exploration and development expenditures of $25.2 million ($15,877 per bopd).

These excellent results are a continuation of the operational momentum, and track record Surge has generated over the last 12 financial quarters – growing production by 77 percent from 12,182 boepd (78 percent liquids) in Q2/16, to 21,544 boepd (84 percent liquids) in Q2/19.

Sparky Core Area

Cost Reductions From First Four Well Pad

In Q2/19, Surge drilled and completed 4 gross (4.0 net) wells in its Sparky core area.

At Provost, Surge drilled four excellent Sparky wells on the Company's first ever four well drilling pad. Due to pad drilling efficiencies, the average "all-in" cost at Provost was $1.04 million per well, compared to budget of $1.25 million per well.  The four wells combined are currently producing over 675 bopd. Surge has more than 35 net drilling locations⁵ remaining at the Company's large, internally estimated 90 million net OOIP⁶, Sparky pool at Provost. As a result of Surge's drilling results at Provost, operating expenses in this area are now $6.75 per boe.

Approximately 18 months ago, Surge announced a large, new Sparky oil discovery at Betty Lake (near Wainwright, Alberta).  The OOIP at Betty Lake is estimated to be over 80 million net barrels. Surge has now largely "de-risked" the Company's Betty Lake Sparky oil pool, drilling eight consecutive horizontal wells, with 100 percent success. Surge estimates that there are more than 50 net locations⁵ remaining to drill at Betty Lake, with full waterflood upside⁷. Based on Surge's excellent drilling results at Betty Lake, operating costs in this field are now $7.00 per boe.

In addition, at a recent Crown sale on July 31, 2019, Surge successfully acquired an additional 8.5 sections of land at Betty Lake – extending this large Sparky pool to the north. The Company believes that this acreage comprises a large Sparky oil pool extension, adding up to an estimated 40 million barrels of net OOIP, and up to 38 additional net drilling locations⁵.  

The Company is also experiencing consistently strong results at its Sparky MM pool at Sounding Lake, with Surge's three most recent wells producing above the Sparky type curve (which has an IP 30 of 100 bopd). Surge estimates more than 30 locations⁵ remaining to be drilled at this large, 25 million OOIP, 31 degree API Sparky asset.

Surge anticipates drilling up to 14 locations in the Sparky core area in 2H/19.

Rapidly Expanding Core Area

In less than five years, in Surge's Sparky core area the Company has amassed more than 900,000,000 barrels of estimated net OOIP, production of over 7,750 boepd (90 percent oil), and over 450 drilling locations - providing a 13 year drilling inventory (at the Company's current pace of 35 Sparky drills per year).

Surge's high quality Sparky reservoirs are characterized as conventional, large OOIP per section (>6mm barrels per section), low risk, shallow, sandstone reservoirs, at 700-800 meters depth. The wells are highly economic, delivering over 135,000 boe (90 percent oil) internally estimated ultimate recovery ("EUR"), for primary production only, at an "all-in" cost of less than $1.2 million per well - drilled, completed and onstream.

Surge's Sparky type curve wells pay out in less than a year, and deliver profit to investment ratios[8] of over 2.0 at current strip oil pricing of US $54 WTI per barrel, for primary drilling. In addition, Surge has successfully proven waterflood upside for the Company's Sparky/Lloyd plays at: Wainwright, Eyehill, Sounding Lake MM, Provost, Macklin, Lakeview, and Silver.

Surge is now utilizing the following technological improvements and efficiencies that the Company's experienced and proven Sparky technical team have integrated over the last 4-5 years:

1. Longer horizontal wells;
2. Monobore drilling;
3. Increased number of frac stages;
4. Less frac intensity per stage;
5. Floating in the casing;
6. Cemented liner;
7. Multi cycle frac sleeves vs "ball-drop" system;
8. Modified mud system; and
9. Pad drilling.

Given these exciting improvements in the Company's drilling and completion processes, Surge has now driven the cost of a Sparky well down from a high of $2.3 million in 2014, to approximately $1.0 million for the Company's two most recent pad wells at Provost. In addition, Surge has also increased the Company's internally generated Sparky type curve production estimates significantly over this period (i.e. by as much as 25-30 percent).

By drilling 105 (out of 106) successful, highly economic, horizontal wells in Surge's Sparky core area over the last five years, the Company has now proven that its proprietary drilling/completion systems deliver excellent results, with remarkable consistency. Management believes this bodes very well for the continued growth and development of Surge's rapidly expanding Sparky play.

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Eyehill – A Case Study

An illustration of Surge's track record for adding value in its Sparky core area is at the Company's high quality, 170 million net OOIP, 29  degree API oil asset at Eyehill. Over the last four years at Eyehill, Surge has: 1) aggressively grown the asset - adding significant value; and 2) strategically transitioned the property into a sustainable, long life, waterflooded asset, as set forth within the Eyehill Production Growth section:

Eyehill – Production Growth > 380 Percent in 3 Years

• Increased production 380 percent in three years.
  
  
• Of the 63 operated horizontal wells at Eyehill, Surge drilled 51 and acquired 12.
  
  
• Peak production of 2,950 boepd was reached in May 2017.
  
  
• Surge had only 15 horizontal wells producing 500 boepd (80 percent liquids) at year end 2015.
  
  
• Surge has drilled an average of 14 wells per year (12 per year excluding acquisitions), increasing production significantly – inclusive of lost production associated with water injector conversions.

To date seven of the 63 wells drilled have now been converted to water injection at Eyehill, providing pressure support and lowering the production decline for this large, conventional Sparky oil pool (i.e. lower annual declines fit very well with Surge's growth and dividend paying business model).

Eyehill - Production Profile (Low Decline Waterflood)

 Based on Surge's strong drilling and waterflood results at Eyehill, operating expenses are now $7.50 per boe.

Eyehill – Value Creation

	Net OOIP (mmbbl)	# of producing Hz's	# of Hz Wtr Injectors	Production (boepd)	% Oil	TPP	TPP
						Reserves (Mboe)	NPV10 ($ millions)
YE 2015	70	15	1	500	80%	4,089	$49
YE 2018	170	56	7	2,400	81%	13,305	$242
3 Yr Change	100	41	6	1,900	1%	9,216	$193
	143%	273%		380%		225%	395%

In the last three years Surge has increased the Company's Sproule NPV10 Total Proved plus Probable reserve value at Eyehill by 395 percent; from $49 million to $242 million.

Surge will continue to follow this proven, disciplined operating strategy of delivering higher initial drilling growth and value creation, followed by strategically transitioning the Company's high quality, large OOIP, Sparky sandstone reservoirs into waterfloods (to deliver long term adjusted funds flow in excess of exploration and development expenditures, and excellent profit to investment ratios) at: Eyehill, Betty Lake, Provost, Sounding MM, Sounding East, Lakeview, Macklin, Cadogan and Eyehill South.

This conservative operating strategy is a key component of Surge's growth plus dividend paying business model.

Valhalla Core Area

At Valhalla, in Q2/19 Surge drilled a successful, 100 percent working interest, Doig horizontal light oil well. This is Surge's third 200 meter horizontal in-fill well drilled into the Doig reservoir, and further validates the continued downspacing of this large, 150 million OOIP net, light oil pool. This well is currently producing more than 750 boepd (70 percent light oil).

Surge estimates an inventory of more than 50 net light oil locations⁵ at Valhalla in the Doig, Charlie Lake and Montney formations, providing a drilling inventory of more than 10 years.

The Company anticipates drilling up to two locations at Valhalla in 2H/19.

Shaunavon Core Area

In Q2/19 Surge drilled 4 gross (4.0 net) successful new wells at Shaunavon. Two of the wells were drilled in the Upper Shaunavon formation, and two were drilled in the Lower Shaunavon formation. The Company also continued its successful pump jack conversion program, with another 30 wells converted to pumpjacks in 1H/19.

Surge estimates over 125 net drilling locations5 remaining in the Upper and Lower Shaunavon formations, and over 400 million barrels of estimated (combined) net OOIP. The Shaunavon field has a high operating netback, is waterflooded, and delivers annual adjusted funds flow in excess of exploration and development expenditures - which fits very well with Surge's lower risk, lower decline, growth and dividend paying business model.

Surge plans for the drilling of up to four additional locations at Shaunavon in 2H/19.

Greater Sawn Core Area

At Greater Sawn, Surge continues to enjoy the significant free adjusted funds flow from this 5,000 bopd light oil asset. The Company drilled its first four wells at Sawn late last year, and early this year, with 100 percent success.

Surge continues to optimize the successful waterflood at Sawn, with plans to expand waterflood operations later this year, and into 2020. Surge estimates a drilling inventory of over 10 years in the Greater Sawn area, with more than 100 net locations⁵ at this high quality, 600 million barrel net OOIP, light oil asset.

Further to the above, at a recent Crown sale on July 31, 2019, Surge successfully acquired an additional 9.5 sections of acreage at Nipisi South in the Company's Greater Sawn core area. Surge believes Nipisi South contains up to 30 million barrels of net OOIP (light oil) in the Slave Point formation, with over 20 additional net Slave Point drilling locations⁵. The new acreage is also prospective for Clearwater oil reserves and production.

The Company anticipates drilling up to four locations at Greater Sawn in 2H/19.

BANK LINE UPDATE

Surge's new borrowing base has been confirmed by its lenders at $500 million, comprised of a $450 million revolving line of credit, and a $50 million operating line of credit (with unanimous lender consent required for the Company to draw in excess of $425 million). On this basis, Surge has over $105 million⁹ of unrestricted liquidity available to the Company, and committed access to over $180 million¹⁰ of total liquidity. 

ENVIRONMENTAL, SOCIAL AND GOVERNANCE

During the first half of 2019 the Company elected to participate in the Alberta Energy Regulators ("AER") Area Based Closure program ("ABC program"). Building on the Company's work in Q1/19, Surge has continued to efficiently direct capital towards abandoning and reclaiming its non-core Cherry natural gas property.

The Company has seen abandonment and reclamation costs continue to be approximately 55 percent of AER estimates, confirming Surge's belief in the economies of scale that are found within the ABC program. Given the Company's success in Q1/19 at Cherry, Surge has now initiated ABC programs in a number of the Company's non-core areas.

Surge has committed $6 million in 2019 to a proactive, well-funded, annual abandonment and reclamation program. This exceeds AER mandated contributions by over $1.8 million, and builds on the $17 million the Company has spent since 2014.

During 1H/19 the Company abandoned 76 wells. The Company has now increased its target abandonment commitment for 2019 from 125 to 150 wells, which is approximately three times the number of wells the Company plans to drill this year.

The Company also continued to advance its Social and Governance leadership by further demonstrating its commitment to diversity in the workplace and on the Board of Directors.  Following the Annual General Meeting, the percentage of female Directors on Surge's Board of Directors increased to 33 percent from 22 percent in Q3/18.  The Company is pleased to not only have increased gender diversity on the Board, but to have added three highly qualified directors with diverse backgrounds, and proven track records, in the past year.

As further evidence of Surge's commitment to Board diversity and renewal, Surge's Board independence has increased to 78 percent in Q2/19 from 71 percent in Q2/18; and the average age of Surge Board members is currently 58 years, down from 62 years in Q2/18.

Surge is a supporter of community engagement and recognizes the importance of supporting charitable organizations and the communities in which the Company operates. Details on the Company's recent community engagement initiatives can be found on Surge's website at www.surgeenergy.ca.

OUTLOOK – CONSISTENT GROWTH; SUSTAINABLE DIVIDEND

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

Surge focuses on sustainability, balance sheet management, and cost controls to deliver returns to Surge shareholders. The Company continues to grow its production base, and 14 year drilling location inventory, in its core areas of Sparky, Valhalla, Greater Sawn, and Shaunavon through low risk development drilling, and waterfloods - in accordance with management's detailed business plan. Surge also strategically applies growth capital to high quality, large OOIP, core area acquisitions.

The Company has an excellent hedging program in place to protect Surge's adjusted funds flow. For 2H/19, Surge has hedged 7,000 bbl/d of WTI crude oil with an average floor price of CAD $78/bbl. This represents approximately 50 percent of Surge's forecasted after royalty crude oil production for 2H/19. Surge has also retained upside to further WTI price increases on 55 percent of the hedged volumes, with an average ceiling of CAD $103/bbl.

On this basis, Surge continues to pay the Company's monthly cash dividend (currently 8 percent yield¹¹). Surge targets dividend payments that range from 20 to 30 percent of adjusted funds flow. Surge paid dividends of $7.9 million in Q2/19, which equates to 15 percent of Q2/19 adjusted funds flow.

APPOINTMENT OF CHIEF FINANCIAL OFFICER - MR. JARED DUCS

Surge is also pleased to announce the promotion of Mr. Jared Ducs to the office of Chief Financial Officer of the Company effective August 9, 2019.  Mr. Ducs has been the Vice President, Finance, of Surge since August 16, 2018, and has been with Surge for over 9 years.

"Jared has been a leader at Surge for many years. His extensive financial, operational, and strategic experience will continue to be a huge asset for the Company," says Surge President and CEO, Paul Colborne.

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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, including its drilling and enhanced recovery plans; Surge's assets and the risks and characteristics associated therewith; Surge's declared focus and primary goals; Surge's dividend policy and sustainability thereof, Surge's plans to grow the monthly dividend; participation in the ABC program and the anticipated benefits therefrom; Surge's plans to abandon certain properties and the timing and benefits thereof, Surge's abandonment and reclamation program and budget; Surge's hedging program; liquidity available to Surge under its credit facility; Surge's decline rates, reserve life index, estimated ultimate recovery, drilling costs and locations, profit to investment ratios, OOIP, estimated 2019 exploration and development capital budget, estimated 2019 net operating, G&A and transportation costs, 2019 production exit rate guidance; 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 continued availability of Surge's credit facility; 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 maintain and/or 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 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.

All drilling locations (booked and unbooked) are further evaluated internally by Surge on an annual basis, and are constructed using a representative, factual and balanced analog data set.  The type curve EUR is measured against OOIP calculations to ensure reasonable recovery factors have been achieved.  Type curves are developed by Surge's internal QRE and fully comply with Part 5.8 of the Companion Policy 51 – 101CP.  Type curve metrics referenced on page 4 & 5 of the press release are derived by using a Surge Sparky type curve which was run on July 30 strip pricing and the 5 year average WCS differential (US$56.62/bbl WTI, US$15.70/bbl WCS differential, 0.761 FX).

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 800 net drilling locations identified herein, of which over 420 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 7 net booked Probable locations. Provost locations identified herein has 15 net booked Proved locations and 7 net booked Probable locations. Sounding Lake Sparky MM Pool locations identified herein has 5 net booked Proved locations and 4 net booked Probable locations. Valhalla locations identified herein has 25.1 net Doig, 5.0 net Charlie Lake and 8.0 net Montney booked Proved locations and 3.9 net Doig, 3.0 net Charlie Lake and 1.0 net Montney booked Probable locations. Shaunavon locations identified herein has 74.0 net booked Proved locations and 17.0 net booked Probable locations. Greater Sawn locations identified herein has 58.4 net booked Proved locations and 21.1 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.

Non-GAAP Financial Measures

Certain secondary financial measures in this press release – namely, "adjusted funds flow", "adjusted funds flow per share", "adjusted funds flow per boe", "net debt", "net operating expenses", "operating netback" and "net debt to adjusted funds flow" 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 and six months ended June 30, 2019 and 2018:

	Three Months Ended					Six Months Ended
($000s except per share)	Jun 30, 2019			Jun 30, 2018		Jun 30, 2019			Jun 30, 2018
Cash flow from operating activities	$	45,807		$	33,725	$	74,715		$	57,940
Change in non-cash working capital		3,126			2,897		14,168			3,395
Decommissioning expenditures		1,111			832		2,818			3,580
Transaction and other costs		698			60		892			768
Cash settled stock-based compensation		-			1,082		-			1,082
Adjusted funds flow	$	50,742		$	38,596	$	92,593		$	66,765
Per share – basic	$	0.16		$	0.17	$	0.30		$	0.29

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.

($000s)	As at June 30, 2019		As at December 31, 2018	As at June 30, 2018
Bank debt	$ (319,503)		$ (408,593)	$ (246,811)
Accounts receivable	38,310		21,084	36,207
Prepaid expenses and deposits	8,113		9,222	8,209
Accounts payable and accrued liabilities	(47,771)		(42,350)	(34,496)
Convertible debentures	(67,552)		(37,973)	(37,328)
Dividends payable	(2,617)		(2,577)	(1,921)
Total	$ (391,020)		$ (461,187)	$ (276,140)

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 and six months ended June 30, 2019 and 2018 are calculated on a per unit basis as follows:

	Three Months Ended					Six Months Ended
($000s except per share)	Jun 30, 2019			Jun 30, 2018		Jun 30, 2019			Jun 30, 2018
Petroleum and natural gas revenue*	$	107,665		$	87,094	$	205,533		$	155,384
Processing and other income*		783			824		1,257			1,705
Royalties*		(13,788)			(12,982)		(24,849)			(21,922)
Operating expenses*		(28,297)			(22,823)		(58,210)			(44,763)
Transportation expenses*		(2,616)			(2,518)		(6,479)			(4,333)
Realized gain (loss) on financial contracts*		(2,537)			(3,829)		(3,253)			(5,411)
Operating netback	$	61,210		$	45,766	$	113,999		$	80,660
G&A expense*		(3,652)			(3,200)		(7,122)			(6,401)
Interest expense*		(6,816)			(3,970)		(14,284)			(7,494)
Adjusted funds flow	$	50,742		$	38,596	$	92,593		$	66,765
Barrels of oil equivalent (boe)		1,960,535			1,553,552		3,907,211			2,996,093
Operating netback ($ per boe)	$	31.24		$	29.46	$	29.17		$	26.91
Adjusted funds flow ($ per boe)	$	25.90		$	24.84	$	23.69		$	22.27
* Taken directly from the financial statements

Net Debt to Adjusted Funds Flow Ratio

Net debt to adjusted funds flow ratio is calculated as net debt divided by annualized adjusted funds flow for the period. This measure provides an indication of leverage and the number of years it would take to repay the net debt based on the level of adjusted funds flow.

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.

^1

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

^2

As at August 8, 2019, based on Reuters estimates.

^3

As compared to the 2019 Capital Budget and Production Guidance press release dated January 14, 2019. Net operating expense guidance was subsequently revised in the first quarter 2019 press release dated May 6, 2019.

^4

Capital efficiencies is calculated as total exploration and development expenditures during the period divided by current Production rates.

^5

See Drilling Locations in the Forward-Looking Statement section of this document for further details.

^6

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

^7

Sproule has not booked any waterflood reserves to this property in the YE2018 report.

^8

Profit to investment ratio (PIR) is calculated as the NPV from a project divided by the capital investment required to realize such cashflows.

^9

Calculated as unrestricted Credit Facility availability of $425 million, less bank drawings of $319.5 million as at June 30, 2019.

^10

Calculated as total borrowing base of $500 million, less bank drawings of $319.5 million as at June 30, 2019.

^11

Calculated as $0.10 annual dividend divided by $1.20 share price.

SOURCE Surge Energy Inc.

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

Related Links

http://www.surgeenergy.ca