SUSTAINABLE CONVENTIONAL RESOURCE COMPANY TSX: SGY FEBRUARY, 2016

Transcription

1 SUSTAINABLE CONVENTIONAL RESOURCE COMPANY TSX: SGY FEBRUARY, 2016

2 REASONS TO OWN SURGE 100% operated, high quality, low decline asset base High quality light/medium crude oil asset base; low decline ~19% ~1.70B (~1.5B net) barrels of OOIP under management; RF~7.7% Return capital to shareholders through dividend and share buyback option $0.15/share annual dividend High netbacks; top tier capital efficiencies Experienced management team with proven track records FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 2

3 SURGE ENERGY Well positioned for growth and sustainable dividends Total Proved plus Probable Reserves of 85.8 mmboe (1) 2016 Average Production Rate 14,000 boepd (76% oil) Low Decline of ~19% (RLI >16 years) Year End 2015 Net Debt: $164MM (unaudited) Bank line: $400 million (only ~41% drawn at YE 2015) Location Inventory: 777/757 (gross/net); 242/224 (gross/net) booked (2) 100% operated in three core areas FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 3

4 2015 YEAR END RESERVE HIGHLIGHTS Maintained reserves and achieved historically low F&D with high quality, large OOIP reservoirs All-in Proved plus Probable F&D of $6.08 per boe Proved plus Probable reserves totaling 85.8 million barrels Maintained 99% of year end 2014 reserves (after a full year of production, economic reserve reductions due to low oil prices, and drilling only 15 wells in 2015) Low 19% corporate decline for Producing and Probable Producing reserves Recorded a 3.9x recycle ratio using 2015 hedged operating netback 55% of reserves are in the Producing and Probable Producing categories FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 4

5 2015 YEAR END RESERVES ~$1.1 Billion of Total Proved plus Probable Reserves Value (NPVBT10) 2015 Year End Reserves Reserve Category Oil& NGLs (Mbbl) Gas (MMcf) Total (Mboe) NPVBT10 ($MM) (1) Proved Producing 24,121 36,369 30,182 $490 Proved Non-Producing 1,115 3,289 1,663 $25 Proved Undeveloped 15,104 34,955 20,930 $202 Total Proved (1P) 40,340 74,612 52,775 $717 Probable 26,559 39,045 33,067 $420 Total Proved + Probable (2P) 66, ,658 85,842 $1,138 *Numbers in the above table may not add exactly due to rounding FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 5

6 2016 CAPITAL PROGRAM Protecting NAV and balance sheet through conservative capital spending OPERATIONAL Average Production (boe/d) for 2016 Capital Spending for ,000 (76% Oil/NGLs) $50 million DCET Waterflood Facilities Workover Land, Capitalized G&A, other $26.9 million $1.5 million $6.2 million $7.7 million $7.7 million Wells Planned in net wells 7 Shaunavon 3 Valhalla Doig 3 Sparky Est Base Decline 19% FINANCIAL Basic Shares Outstanding Annual Dividend Payable million $33.2 million ($0.15 per share per annum) FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 6

7 $50MM(e) CAPEX TO MAINTAIN 14,000 BOE/D IN 2016 Maintaining production with modest capital as a function of low corporate declines and excellent well results Estimated 2016 Capital Required to Maintain 14,000 boe/d Capital Allocation Area # of Drills Capital / Well ($MM / DCET) Total Capital ($MM) IP365 Production Adds (boe/d) Valhalla 3 $3.6 $10.8 1,200 Shaunavon 7 $1.6 $ Sparky 3 $1.4 $ Waterflood $ Maintenance / Facility Work Land, G&A, Other $7.7 $ Total 13 $49.3 2,545 Surge guidance estimated ~$50 million capex in 2016 to maintain an annualized production rate of 14,000 boe/d using the previous decline estimate of 21% Maintenance capital is further minimized due to a confirmed low corporate base decline of 19% in 2016, top tier conventional assets, and industry leading PE s / ROR s Replacement of ~2,255 boe/d is required to maintain production of 14,000 boe/d Surge s low corporate decline of 19% is a direct reflection of Surge having 12 of 17 reporting properties currently under waterflood, and targeting development in large OOIP, conventional reservoirs. FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 7

8 ELITE ASSETS FOCUSED IN THREE CORE AREAS Large OOIP pools in established conventional reservoirs Surge 2015 Exit Production: Total: >14,500 boe/d (76% Oil & NGL s) (~57% on AB Crown) Western Alberta Production: Total: ~7,900 boe/d (66% Oil & NGL s) SE AB Production: Total: ~3,700 boe/d (88% Oil & NGL s) Shaunavon Production: Total: ~2,900 boe/d (100% Oil & NGL s) FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 8

9 CORE AREA DETAILS ~1.5 Billion bbl s net OOIP with potential to recover an additional ~125 Million net unbooked bbl s Core Area Western Alberta Formations Doig/Slave Point/ Bluesky/Montney/ Banff/Doe Creek /Wabamun OOIP (MMbbls) Drilling Locations Avg. WI CTD Oil Total Booked Independent Recovery Recovery Factor P+P (1) Factor (1) Gross/Net Gross/Net (2) (% OOIP) Internally Estimated Ultimate Recovery Net (Waterflood with Development Drilling) 711/ /192 85% 7.3% 12.1% 23% SE Alberta Mannville Group 506/ /170 85% 15.1% 19.1% 25% SW Saskatchewan Shaunavon 469/ /395 98% 1.2% 3.8% 13% TOTALS: 1,686/1, /757 88% 7.7% 11.6% 20% FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 9

10 TARGETING CONVENTIONAL RESERVOIRS Large OOIP, high quality reservoirs tend to get larger over time Conventional reservoirs tend to outperform over time: Year over year recovery factor reserve additions Long life, low decline production Higher ultimate recoveries Enhanced oil recovery by applying proven technology Characteristics of conventional reservoirs: High porosity - large oil storage; large OOIP High permeability - better fluid flow as porosity is highly interconnected Greater confidence in achieving recovery factors (vs unconventional/tight) Lower risk drilling and enhanced recovery with application of technology Higher probability of successful waterflood implementation increasing oil recovery factors FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 10

11 Ultimate Oil Recovery ROR CONVENTIONAL VS. UNCONVENTIONAL RESERVOIRS Surge targets reservoirs on the conventional end of the permeability spectrum Capital expenditures decrease, while recovery factors and rates of return increase, as reservoir quality improves. Unconventional Reservoirs Conventional Reservoirs Extremely Tight Duvernay Very Tight Tight Low Moderate High Montney Resource Valhalla Doig Viking-Cardium Halo Shaunavon *Modified from US Department of Energy Study Permeability (md) Average Surge Permeability Sparky FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 11

12 THREE CORE CONVENTIONAL RESERVOIRS Applying proven technology to conventional reservoirs helps provide top tier performance and higher recovery factors U. Shaunavon Valhalla Doig Sparky Depth 1450m Depth 2000m Depth 725m Net Pay 4-10m Net Pay 15-35m Net Pay 8-12m Porosity 12-18% Porosity 6-10% Porosity 18-29% Permeability Up to 500mD Permeability Up to 100mD Permeability Up to 500mD Sw (%) 30-40% API Sw (%) 20% API 41 Sw (%) 40-50% API 28 OOIP/Sec (Average) 4 9 MMBbls OOIP/Sec (Average) 7 14 MMBbls OOIP/Sec (Average) 8 16 MMBbls Net OOIP >250 MMbbls Net OOIP >130 MMbbls Net OOIP >350 MMbbls Surge is focusing capital to three core conventional plays; all of which have excellent reservoir characteristics which in turn lead to top tier PE s, ROR s and higher recovery factors. FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 12

13 TOP TIER CAPITAL EFFICIENCIES AND REPLACEMENT METRICS Large inventory with excellent economics using December 2015 strip pricing Core Area Areas/Formations Locations (Gross / Net) Capital Efficiency Rates of Return (1) (December 2015 Strip Pricing) Drill/ Complete/ Equip 180 day IP Mboe/well (on primary) SW Sask Western Alberta SE Alberta Upper Shaunavon (214/212) Valhalla (Doig) (47/41) Sparky (136/135) $11,200/boepd 66% $1.6 MM 145 boepd (100% oil) 150 $6,500/boepd 171% $3.6 MM 550 boepd (68% oil) 420 $12,700/boepd 42% $1.4 MM 110 boepd (73% oil) 120 *Numbers in the above table are based on Surge s internally generated type curves and realized DCET capital reductions of ~20-30%. FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 13

14 QUALITY WATERFLOOD PROJECTS Waterflood - increasing reserves & flattening declines Current Properties Under Commercial Waterflood Area Formation Start Date 2015 Decline Current RF Booked RF Expected RF Silver Lloyd/ Cummings % 12.6% 35.7% 39.0% Wainwright Sparky % 32.0% 35.5% 37.1% Macklin Sparky % 10.4% 37.2% 38.0% Valhalla Doe Creek % 12.5% 16.1% 38.5% Chip Lake Rock Creek % 7.2% 11.8% 15.0% Sunset Montney % 24.4% 38.3% 41.3% Westerose Banff % 6.1% 7.3% 10.0% Nipisi Slave Point % 3.3% 8.8% 20% Nevis Wabamun % 3.1% 5.4% 20% Windfall Bluesky % 2.1% 4.5% 15% Eyehill Sparky % 0.2% 3.0% 20% Area Formation Start Date Shaunavon Upper Shaunavon Current Waterflood Pilots # of Injectors Analog Property Q Shaunavon Future Waterflood Pilots Comments Initiated flood in Q3 2015; 2 injectors implemented; numerous successful analogues in the Upper Shaunavon trend Provost Sparky Wainwright Q1/13 discovery; ~65 MM OOIP FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 14

15 SOUTHWEST SASKATCHEWAN - SHAUNAVON >450MM barrels of net OOIP in the Upper and Lower Shaunavon combined >450 MMbbls of net OOIP in the Lower and Upper Shaunavon formations (medium gravity oil) Current combined recovery factor ~1.2% Rates of return in excess of 66% (1) for the Upper Shaunavon 401/395 (gross/net) drilling locations in the Lower and Upper Shaunavon Operated facilities, including: pipeline connected battery, waterflood infrastructure, and a nearby rail transloading facility Fully unbooked waterflood upside from a conventional sandstone reservoir, in a trend with proven waterflood implementation Surge Land Surge Wells FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 15

16 T4 T6 T8 T10 UPPER SHAUNAVON Large contiguous undeveloped land position in the greater Upper Shaunavon trend R21W3 R19W3 Instow Area/Pool Well Count Depth OOIP Cum Oil Peak Rate Current Rate Vt Hz (m) (MMbbl) (MMbbl) (bbl/d) (bbl/d) Instow , ,420 2,480 Dollard , ,660 1,540 Eastbrook* , ,760 3,690 Rapdan , ,490 1,300 SGY Eastend* , TBD >1,500 Data from public sources Dollard 20 Upper Shaunavon horizontal wells drilled and on production Eastend Q Waterflood Pilot; 2 horizontal injector conversions completed in early Q3 Eastbrook Upper Shaunavon currently estimated to have >250MMbbls net OOIP; >200 net locations on Surge owned acreage Rapdan SGY Lands Upper Shaunavon Wells Surge Upper Shaunavon Wells FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 16

17 T4 T5 T6 T7 UPPER SHAUNAVON ACTIVITY >250MMbbl OOIP on Surge lands in the Upper Shaunavon R21W3 R20W3 R19W3 Upper Shaunavon A Sand Upper Shaunavon B Sand Upper Shaunavon C Sand Lower Shaunavon SGY Q3 Waterflood Pilot W3 SGY Q1 15 U. Shvn Hz 191/ W3 On Prd March 2015 IP (90) = 219 BOPD SGY Q3 15 U. Shvn Hz 191/ W3 On Prd Aug 2015 IP(90) = 151 BOPD SGY Q3 15 U. Shvn Hz 191/ W3 On Prd Aug 2015 IP(90) = 300 BOPD Progression of Upper Shaunavon Development SGY Lands Upper Shaunavon Oil Fairway SGY Upper Shaunavon Drills Q Upper Shaunavon Wells Upper Shaunavon Producing Well Upper Shaunavon Water Injector FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 17

18 Rate (bopd), Cum Oil (mbbl) UPPER SHAUNAVON PERFORMANCE Surge horizontal results in the Upper Shaunavon outperforming area average 400 Upper Shaunavon Monthly Production vs Area Average Primary EUR 150Mbbl Month FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 18

19 NORTHWEST ALBERTA Large OOIP >700MMbbls in concentrated high quality light oil assets Large OOIP of >700 (600 net) MMbbls of high quality light oil (32-40 API) Valhalla OOIP: 228 mmbbl (195 mmbbl net) Sunset OOIP: 28 mmbbl (28 mmbbl net) Nipisi OOIP: 155 mmbbl (150 mmbbl net) Windfall OOIP: 60 mmbbl (60 mmbbl net) Westerose OOIP: 84 mmbbl (57 mmbbl net) Nevis OOIP: 160 mmbbl (135 mmbbl net) Current Production ~7,900 boe/d (66% Oil and NGL s) Large development inventory of 204 (192 net) locations Successful waterfloods implemented at: Valhalla: Doe Creek Sunset: Montney Nipisi: Slave Point Windfall: Bluesky Nevis: Wabamun Westerose: Banff Chip Lake: Rock Creek FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 19

20 NORTHWEST ALBERTA - VALHALLA Firm service agreements for Alliance and TCPL pipelines mitigates production restrictions Doe Creek Oil Pool >60MMbbl Surge W6 CNQ W6 Gas Plants TCPL & Alliance Connected Surge Land Surge Wells Pipeline Options Conoco Wembley W6 Gas Plant TCPL & Alliance Connected Valhalla Wembley Sexsmith W6 Gas Plant TCPL & Alliance Connected Doig Oil Pools ~130MMbbl s Valhalla Doig ~130 MMbbls of net combined OOIP on Surge s Valhalla and Wembley Lands (40 API light oil) Rates of return of 171% (1) Current recovery factor ~3.5% 47/41 (gross/net) drilling locations at Valhalla and Wembley Continued delineation of large pool extension to the North Potential future waterflood candidate Facility Options Surge anticipates minimal production interruptions at Valhalla due to firm service agreements Surge is currently producing Valhalla gas through the Gas plant, Sexsmith, and Wembley gas plants all of which are dual connected with access to Alliance and TCPL Construction of the pipeline connecting North Valhalla to W6 and W6 is complete, sales began mid December 2015 Compressor installation to reduce field line pressure is scheduled to be online by end of February 2016 FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 20

21 Cum (boe) VALHALLA DOIG PERFORMANCE 2015 drilling in Valhalla yielded 3 of the top oil wells in Canada North Valhalla Doig 03/ W6 Hz Recent drilling results outperforming type curve and exceeding expectations Optimization of drilling and completion techniques are improving results and lowering capex 200m infill spacing is optimal for proper exploitation the 25+m thick Doig reservoir 03/ W6 Hz 00/ W6 Hz (Q1 2015) 300, , ,000 Valhalla Doig Performance 03/ /15-06 SGY Wells Normalized Cum Area Avg Normalized Cum AVG PUD 150,000 00/ W6 Hz 100,000 50,000 Surge Land Doig Penetrations Surge Doig Locations Months FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 21

22 SOUTHEAST ALBERTA - SPARKY Provost / Eyehill / Wainwright area s Oil saturated Cretaceous sands Wainwright >430 MMbbls of net OOIP (23-31 API oil) Current recovery factor of ~15% Current production: ~3,700 boe/d Eyehill Sparky waterflood implemented in Q4 2014; Provost waterflood pilot expected to start in 2016 Silver Macklin Provost Control of key infrastructure Rates of return in excess of 42% (1) 172/170 (gross/net) drilling locations Eye Hill Surge Land Surge Wells FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 22

23 POSITIONED FOR LONG TERM SUSTAINABILITY Low base decline <19%, high netbacks, excellent capital efficiencies $0.15 annual dividend; NO DRIP! ; Share buyback in place Excellent balance sheet one of the best in the peer group FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 23

24 HIGH QUALITY CRUDE OIL ASSET BASE Focused, high quality, crude oil asset and opportunity base; 3 core areas are 100% operated, with working interests of ~90% Large OOIP crude oil reservoirs with low recovery factors; >16 year RLI Over 700 net low risk development drilling locations provide >12 year drilling inventory FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 24

25 ANALYST COVERAGE Financial Institution Analyst Address Acumen Capital Partners Trevor Reynolds BMO Capital Markets Ray Kwan Canaccord Genuity Anthony Petrucci CIBC World Markets Inc. Jeremy Kaliel Clarus Securities Inc. Josie Ho Cormark Securities Inc. Garett Ursu Dundee Securities Corporation Chad Ellison FirstEnergy Capital Corp. Cody R. Kwong GMP Securities L.P. Grant Daunheimer Mackie Research Capital Corp. David Ricciardi Macquarie Securities Group Brian Bagnell National Bank Financial Dan Payne Paradigm Capital Ken Lin Peters & Co. Limited Dale Lewko RBC Capital Markets Shailender Randhawa Scotia Capital Inc. Cameron Bean TD Securities Juan Jarrah FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 25

26 CORPORATE PARTNERS Advisors Bankers Syndicate: Auditor: Legal Counsel: Evaluation Engineers: Registrar & Transfer Agent: Investor Contacts: National Bank of Canada Bank of Nova Scotia Canadian Imperial Bank of Commerce Toronto-Dominion Bank Bank of Montreal ATB Financial HSBC Bank Canada Wells Fargo Goldman Sachs KPMG LLP McCarthy Tétrault Sproule Associates Ltd. Computershare Canada Paul Colborne, President & CEO Paul Ferguson, CFO 2100, th Ave. SW, Calgary Alberta T2P 3M3 T: F:

27 FORWARD-LOOKING STATEMENTS FORWARD-LOOKING STATEMENTS This presentation contains forward-looking statements. More particularly, this presentation contains statements concerning anticipated: business strategies, plans and objectives; potential development opportunities and drilling locations, expectations and assumptions concerning the success of future drilling and development activities, the performance of existing wells, the performance of new wells, decline rates, recovery factors, the successful application of technology and the geological characteristics of our properties; cash flow; timing and amount of future dividend payments; oil & natural gas production growth and mix; reserves; debt and bank facilities; amounts and timing of capital expenditures; hedging results; primary and secondary recovery potentials and implementation thereof; and drilling, completion and operating costs. Statements relating to "reserves" are deemed to be forward looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future. Actual reserve values may be greater than or less than the estimates provided in this presentation. Cash dividends on our common shares are paid at the discretion of our Board of Directors and can fluctuate. In establishing the level of cash dividends, the Board of Directors considers all factors that it deems relevant, including, without limitation, the outlook for commodity prices, our operational execution, the amount of funds from operations and capital expenditures and our prevailing financial circumstances at the time. The forward-looking statements are based on certain key expectations and assumptions made by Surge, including expectations and assumptions concerning the performance of existing wells and success obtained in drilling new wells, anticipated expenses, cash flow and capital expenditures and the application of regulatory and royalty regimes. 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 forwardlooking 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 uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures. Certain of these risks are set out in more detail in Surge s Annual Information Form which has been filed on SEDAR and can be accessed at Readers are cautioned that the foregoing list of risk factors is not exhaustive. New risk factors emerge from time to time, and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factor on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. The above summary of assumptions and risks related to forward-looking statements in this presentation has been provided in order to provide potential investors with a more complete perspective of our current and future operations and as such information may be not appropriate for other purposes. The forward-looking statements contained in this presentation 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. 27

28 ENDNOTES Slides 3 & 9: Slide 5: (1) December 31, 2015 reserves. (2) This presentation discloses drilling locations in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations, which are sometimes collectively referred to as booked locations, are derived from the Company s most recent independent reserves evaluation as of December 31, 2015 and account for drilling locations that have associated proved or probable reserves, as applicable. Unbooked locations are internal estimates based on the Company s prospective acreage and an assumption 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. Of the 757 net drilling locations identified herein, 149 net are proved locations, 75 net are probable locations and 533 are unbooked locations. Unbooked locations have specifically been identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves data on prospective acreage and geologic formations. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results and other factors. (1) Based on Sproule's December 31, 2015 Revised Price Forecast Slides 13,15, (1) Dec 1, 2015 strip price forecast (2016 WTI: US$45.80/bbl; Henry Hub: US$2.45/mmbtu); a 1.5% per year inflation rate was applied from 20, 22: end of forecast to An inflating CAD/USD exchange rate of $0.76 (to $0.90 by 2052) was assumed. 28

29 OIL AND GAS ADVISORY "In this presentation, "Boe" means barrel of oil equivalent on the basis of 6 mcf of natural gas to 1 bbl of oil. Boe's may be misleading, particularly if used in isolation. A boe conversion ratio of 6mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In addition, given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6: 1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. In this presentation: (i) mcf means thousand cubic feet; (ii) mcf/d means thousand cubic feet per day (iii) mmcf means million cubic feet; (iv) mmcf/d means million cubic feet per day; (v) bbls means barrels; (vi) mbbls means thousand barrels; (vii) mmbbls means million barrels; (viii) bbls/d means barrels per day; (ix) bcf means billion cubic feet; (x) mboe means thousand barrels of oil equivalent; (xi) mmboe means million barrels of oil equivalent and (xii) boe/d means barrels of oil equivalent per day. The estimated values of the future net reserves of the reserves disclosed in this presentation do not represent the market value of such reserves. The estimates of reserves and future net reserve for individual properties may not reflect the same confidence level as estimates of reserves and future net reserve for all properties due to the effects of aggregation. 29

30 NON-GAAP MEASURES NON-GAAP MEASURES This presentation includes non-gaap measures as further described herein. These non-gaap measures do not have a standardized meaning prescribed by International Financial Reporting Standards ( IFRS or, alternatively, GAAP ) and, therefore, may not be comparable with the calculation of similar measures for other entities. Basic payout ratio is calculated as cash dividends declared divided by funds from operations. Cash dividends per share represents cash dividends declared per share by Surge. Funds from operations represents cash flow from operating activities adjusted for changes in non-cash working capital, decommissioning expenditures, cash settled stock-based compensation and transaction costs. Management believes that funds from operations is a useful supplemental measure that provides an indication of the results generated by the Company's principal business activities before the consideration of how those activities are financed or how the results are taxed. Netbacks is used by the Company to help evaluate its performance as well as to evaluate acquisitions. The Company considers netbacks as a key measure as it demonstrates its profitability relative to current commodity prices. Operating netbacks are calculated by taking total revenues (excluding derivative gains and losses) and subtracting royalties, operating expenses and transportations costs on a per boe basis. Net debt is calculated as outstanding bank debt plus or minus working capital, however, excluding the fair value of financial contracts and other current obligations. Net debt is used by management to analyze the financial position and leverage of Surge. Total Payout Ratio is calculated as development capital plus cash dividends declared divided by funds from operations. 30