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Presentation on theme: "POSITIONED FOR LONG TERM SUSTAINABILITY TSX: SGY FEBRUARY, 2015."— Presentation transcript:


2 FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES RECENT DEVELOPMENTS Strong 2014 Reserves, Record Production Levels and Debt Reduction  2014 Year End Reserve Highlights New NAV of $7.36 per share (December 31, 2014) “All in” FD&A costs for 2014 of $19.55 per boe and recycle ratio of > 2.2 times Increased YOY 2P reserves by 52% from 73.5MMboe to 112.0 MMboe 2P FDC (10%) is only 2.3 times 2014 forecast average funds flow Maintained corporate PDP value year/year despite the plunge in crude pricing >50% of Surge’s $2.0B total 2P NPV10 value resides in the PDP category Initiated bank line review and expect to maintain $725MM bank line based on strong reserve results, before the impact of the oil hedge reconfiguration and non-core property disposition  Corporate Highlights: Averaged 2014 production of 18,070 boe/d, an increase of 68% over 2013 Sold non-core assets for proceeds of $35.6MM Monetized in the money crude oil swaps at a profit of >$35MM Re-hedged approximately 45% of production by way of a “costless collar” with an avg floor of over C$62/bbl (1) and a ceiling of over C$82/bbl (1) for the remainder of 2015 2

3 FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES REASONS TO OWN SURGE Well managed, operated, high quality, low decline asset base  High quality light/medium crude oil asset base; low decline <22%  >2.0 Billion barrels of OOIP under management; low RF~8%  Low “all-in” sustainability ratio of 65% (US$58 WTI) ($0.30 annual dividend)  High netbacks; top tier capital efficiencies  Experienced management team with proven track records 3

4 FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES FIRST HALF 2015 CAPITAL PROGRAM @ US$58 WTI Protecting NAV and balance sheet through conservative capital spending OPERATIONAL Average Production (boe/d) for 1H 2015>20,000 (83% Oil/NGLs) Capital Spending for 1H 2015$22 million Wells Drilled in 1H 20155/3.8 gross/net wells 2 Shaunavon 1 Sparky 0.8 Midale Est Base Decline< 22% FINANCIAL (1) 1H 2015 Operational Netback$31.65/boe Basic Shares Outstanding220 million Annual Dividend Payable$66 million ($0.30 per share per annum) 1H 2015 Basic Payout Ratio41% “All-in” 1H 2015 Sustainability Ratio65% 4

5 FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES ELITE ASSETS FOCUSED IN THREE CORE AREAS Western Alberta Production: Total: ~6,700 (67% Oil & NGL’s) SE AB/SW SK Production: Total: ~9,450 (88% Oil & NGL’s) Williston Basin Production: Total: ~5,200 (100% Oil & NGL’s) Surge 2014 Exit Production: Total: 21,350 (84% Oil & NGL’s) Large OOIP pools located in established oil charged trends 5

6 FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES CORE AREA DETAILS >2 Billion bbl’s OOIP with potential to recover an additional ~261 Million bbl’s net to Surge without the Viking Core AreaFormations OOIP (MMbbls)Drilling Locations Avg. WI CTD Oil Recovery Factor Total Booked Independent Recovery Factor P+P (1) Internally Estimated Ultimate Recovery Net (Waterflood with Development Drilling) Gross/Net (% OOIP) Western Alberta Doig/Slave Point/ Bluesky/Montney/ Banff/Doe Creek /Wabamun 731/626187/17889%5.7%11.4%23% SE AlbertaMannville Group481/399152/14983%16.7%20.7%25% SW Saskatchewan Shaunavon469/467362/35697%0.9%3.1%13% Williston Basin Midale / Frobisher-Alida / Bakken-3 Forks 689/562217/19982%12.6%17.0%23% TOTALS:2,370/2,054918/88287%8.3%12.5%21% 6

7 FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES TOP TIER CAPITAL EFFICIENCIES AND REPLACEMENT METRICS Vast opportunity base allows for selective and efficient capital allocation *Numbers in the above table are based on Surge’s internally generated type curves Core Area Areas/Formations Capital Efficiency Rates of Return % (1) Drill/ Complete/ Equip (2) 180 day IP Mboe/well (on primary) Locations $55 WTI$58 WTI$65 WTI$75 WTI (Gross / Net) Western Alberta Valhalla$14,100/boepd57%62%77%105%$3.95 MM280 boepd (69% oil)420 (39/31) SE Alberta/ SW Sask Upper Shaunavon$11,800/boepd76%87%122%197%$1.95 MM165 boepd (100% oil)150 (175/174) Sparky$15,500/boepd60%64%75%95%$1.70 MM110 boepd (73% oil)120 (116/115) Williston Basin Midale Crown$20,000/boepd53%57%66%84%$1.80 MM90 boepd (100% oil)100 (24/17) Midale SGY Fee$20,000/boepd58%62%73%92%$1.80 MM90 boepd (100% oil)100 (93/84) Mississippian – Frobisher/Alida $15,600/boepd43%48%60%85%$1.25 MM80 boepd (100% oil)75 (40/31) Manson – Bakken/Torquay $20,800/boepd54%58%69%90%$1.35 MM65 boepd (100% oil)80 (37/33) 7

8 FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES QUALITY WATERFLOOD PROJECTS Increasing reserves / flattening declines through waterflood implementation Current Waterflood Pilots Area FormationStart Date # of Injectors Analog Property Comments NipisiSlave PointQ2 20134Gift 4th injector in Aug 2014; results to date encouraging; analog pool is commercial MansonBakkenQ4 20137SinclairInitial results are encouraging; analog pool is commercial Shaunavon Lower Shaunavon Q4 20135Shaunavon Piloting 200 and 400 m spacing; 3 analog pilots showing strong oil response. NevisWabamunQ3 20102N/A 2 nd injector commenced in Q1 2014; increasing source water supply to increase injection MacounMidaleQ4 20131Benson1st Hz injector in the pool; analog pool is commercial WindfallBlueskyQ4 20121N/A91,000 m3 injected; offset declines are flattening EyehillSparkyQ3 20141WainwrightQ1/13 discovery; > 80 MM OOIP 2015 Waterflood Pilots ProvostSparkyQ41-2WainwrightQ1/13 discovery; > 45 MM OOIP Current Properties Under Full Commercial Waterflood AreaFormationStart Date2014 DeclineCurrent RFBooked RFExpected RF Silver Lloyd/ Cummings 199618%12.6%35.7%39.0% WainwrightSparky19628%32.0%35.5%37.1% MacklinSparky200518%10.4%37.2%38.0% ValhallaDoe Creek19946%12.5%16.1%38.5% 8

9 FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES  >400 MMbbls of Net OOIP in the Lower and Upper Shaunavon formations (medium gravity oil)  Current recovery factor ~0.9%  Rates of return in excess of 87% (1) for the Upper Shaunavon  362 gross/356 net drilling locations in the Lower and Upper Shaunavon based on 8 wells/section  Operated facilities, including: pipeline connected battery, waterflood infrastructure, a nearby rail transloading facility, and an existing rail marketing arrangement  Development of the Upper Shaunavon discovery has begun with 9 wells on production by year end 2014 and an additional 2 wells to be on production in Q1 2015 SOUTHWEST SASKATCHEWAN - SHAUNAVON >400MM barrels of Net OOIP in the Upper and Lower Shaunavon combined Surge Land Surge Wells 9

10 FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES UPPER SHAUNAVON Large contiguous undeveloped land position in the Upper Shaunavon trend T6 T8 T10 T4 R21W3 R19W3 Instow Leitchville Leon Lake Dollard Rapdan Eastbrook Eastend Upper Shaunavon Wells SGY Lands 10 Area/PoolWell CountDepthOOIPCum OilPeak RateCurrent Rate VtHz(m)(MMbbl) (bbl/d) Instow11821372152.469.694202530 Leitchville68209137198.914.565905080 Leon Lake2822137174.74.21270 Dollard10961402179.3103.5146601680 Eastbrook28221420n/a8.437603430 Rapdan103101410143.231.544901050 SGY - Eastend011*1430200+0.2TBD>1200 * SGY well count includes 2 January 2015 drills scheduled for completion February 2015 Data from public sources  Surge Upper Shaunavon 9 wells drilled and completed in 2014 (Currently >1200 bopd) 5 wells drilled and completed in Q4 2014 with 30 day IP rates over 200 bopd 5 th well was a step-out and validated a large additional Upper Shaunavon trend 2 Upper Shaunavon wells drilled in Q1 2015 with completions scheduled for Feb 2015 Discovery >200MMbbls OOIP; over 100 locations

11 FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES UPPER SHAUNAVON ACTIVITY >150MMbbl OOIP on Surge lands in the Upper Shaunavon B Sand SGY Lands R20W3 T6 T7 R19W3 T5 T4 R18W3 CPG U. Shvn Hz 191/14-13-005-20W3 On Prd Jan 2014 IP(90) = 248 BOPD Cum(YTD) = 44.2 mbbl Upper Shaunavon Depositional Trend Upper Shaunavon Seismically Identified “Sweet Spots” SGY Licensed Locations SGY 2014 Upper Shaunavon Drills Upper Shaunavon Wells SGY Q4 ‘14 U Shvn Hz 192/03-25-005-20W3 On Prd Dec 2014 Avg. 297 bbl/d (66 days) Cum(YTD) = 21.1 mbbl CPG U. Shvn Hz 191/02-36-004-20W3 On Prd Jan 2013 IP(90) = 287 BOPD Cum = 99 mbbl SGY Q4 ‘14 U.Shvn Hz 191/04-34-005-19W3 On Prd Dec 2014 Avg. 164 bbl/d (48 days) Cum(YTD) = 9.1 mbbl SGY Q4 ‘14 U. Shvn Hz 191/01-25-005-20W3 On Prd Dec 2014 Avg. 125 bbl/d (67 days) Cum(YTD) = 9.6 mbbl SGY Q3 ‘14 U. Shvn Hz 192/13-31-005-19W3 On Prd Sept 2014 IP(90) = 240 BOPD Cum(YTD) = 28.8 mbbl CPG U. Shvn Hz 191/13-20-006-19W3 On Prd Mar 2011 IP(90) = 109 BOPD Cum(YTD) = 24.5 mbbl SGY Q1 ‘14 Upper Shvn Hz 191/16-36-005-20W3 IP(90) = 250 BOPD Cum(YTD) = 68.5 mbbl Lower Shaunavon Upper Shaunavon A Sand Upper Shaunavon B Sand Upper Shaunavon C Sand 11

12 FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES UPPER SHAUNAVON PERFORMANCE Surge results in the Upper Shaunavon exceeding expectations 12

13 FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES SOUTHEAST SASKATCHEWAN - WILLISTON BASIN Midale, Macoun and Pinto Areas – Large Fee and Crown position in Midale Carbonate trend  211 MMbbls of Net OOIP (35-37 degree API)  Current recovery factor ~5% of OOIP  Rates of return >57% (1)  38,400 acres (60 sections) of Surge Fee land  142 gross/123 net drilling locations 93/84 (gross/net) FEE Locations 24/17 (gross/net) Crown Locations 25/22 (gross/net) Freehold Locations Surge Fee Land Surge Land Surge Wells Macoun Midale Weyburn Pinto 13

14 FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES SOUTHEAST ALBERTA Provost / Eyehill / Wainwright Area’s – Oil saturated Cretaceous Sands  >400 MMbbls of Net OOIP (23-31 degree API oil)  Current recovery factor of ~14%  Eyehill Sparky waterflood started in Q4 2014 and Provost waterflood pilot expected to start in 2015  Control of key infrastructure  Rates of return in excess of 64% (1)  152 gross/149 net drilling locations Surge Land Surge Wells Wainwright Silver Macklin Eyehill Provost 14

15 FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES WESTERN ALBERTA >195MMbbls OOIP in Oil rich Doig and Doe Creek Formations Surge Land Surge Wells Doe Creek Oil Pool Doig Valhalla Wembley  >130 MMbbls of Net combined OOIP at Valhalla and Wembley (40 degree API light oil)  Rates of return of 62% (1)  Current recovery factor ~2.8%  39 gross/31 net drilling locations at both Valhalla and Wembley  Continued delineation of large pool extension to the North  Potential future waterflood candidate  >60MMbbls of OOIP (37° API oil)  Current recovery factor 13%  Low historical declines of 8-10%/year  100% WI and operated  Currently under waterflood with optimization opportunities  Acquired working interest in a gas plant capable of processing associated gas volumes from Surge’s Valhalla Doig oil pool Valhalla Doe Creek Oil Pool Valhalla Doig 15

16 FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES PeriodCurrencybbls/d Avg Price (Floor / Ceiling) Mar – Dec 2015 CAD3,000$61.67 / $83 Mar – Dec 2015 USD2,500$50 / $65.40 RISK MANAGEMENT / HEDGING STRATEGY Oil Hedges  The Company has an orderly, on-going, risk management / hedging program designed to lock in future cash flows to protect the Company’s capex program and fund dividends.  Surge has 5,500 barrels per day of WTI hedged (~ 41% 1H net oil + NGL’s) with a costless collar structure, as follows: WCS Differential Hedges bbls/d hedged WTI-less USD$/bbl 20153,000$22.10 20161,000$21.75 EDM Light Differential Hedges bbls/d hedged WTI-less USD$/bbl Q1 20152,000$8.34 Q2 20151,000$8.19 16  Surge has 7,586 mcf per day of AECO hedged (~50% net natural gas) at CAD$4.14 for 2015.

17 FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 17 2014 YEAR END RESERVES ~$2.0 Billion of Total Proved plus Probable Reserves Value (NPVBT10) 2014 Year End Reserves Reserve Category Oil& NGLs (Mbbl) Gas (MMcf) Total (Mboe) NPVBT10 ($MM) (1) Proved Producing36,834 51,587 45,431 $1,038 Proved Non-Producing7332,4241,137 $25 Proved Undeveloped16,64730,62821,752 $261 Total Proved (1P)54,21484,63968,320$1,324 Probable36,01746,15643,710 $661 Total Proved + Probable (2P)90,230130,795112,030$1,984 *Numbers in the above table may not add exactly due to rounding

18 FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES POSITIONED FOR LONG TERM SUSTAINABILITY  Low base decline <22%, high netbacks, excellent capital efficiencies  Very low “all-in” sustainability ratio of 65%; NO DRIP!  Ongoing risk management/hedging program protects cash flow 18

19 FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES  Focused, high quality, crude oil asset and opportunity base; core properties are 100% operated with working interests of ~90%  Elite, large OOIP crude oil reservoirs – with low recovery factors; >15 year RLI (only ~2 years of FDC/cash flow)  Over 900 gross low risk development drilling locations provide >12 year inventory; Of these >400 are grade “A” development locations - providing >35,000 boepd of low risk upside HIGH QUALITY CRUDE OIL ASSET BASE 19

20 FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES ANALYST COVERAGE Financial InstitutionAnalystEmail Address BMO Capital MarketsJim Canaccord GenuityAnthony CIBC World Markets Inc.Jeremy Cormark Securities Inc.Garett Dundee Securities CorporationChad FirstEnergy Capital Corp.Cody R. GMP Securities L.P.Grant Macquarie Securities GroupRay National Bank FinancialDan Paradigm CapitalKen Peters & Co. LimitedDale RBC Capital MarketsShailender Scotia Capital Inc.Cameron TD SecuritiesJuan 20

21 2100, 635 – 8 th Ave. SW, Calgary Alberta T2P 3M3 T: 403.930.1010 F: 403.930.1011 Advisors Bankers: National Bank of Canada Bank of Nova Scotia Canadian Imperial Bank of Commerce Toronto-Dominion Bank Bank of Montreal JPMorgan Chase Bank, N.A. ATB Financial HSBC Bank Canada Auditor:KPMG LLP Legal Counsel:McCarthy Tétrault Evaluation Engineers: Sproule Associates Ltd. McDaniel & Associates Consultants Ltd. Registrar & Transfer Agent:Computershare Canada Investor Contacts: Paul Colborne, President & CEO Max Lof, CFO CORPORATE PARTNERS 21

22 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 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 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. 22

23 ENDNOTES Slide 2:(1) USD$ WTI hedges have been converted to $CAD, based on Feb-9-2015 strip rate. Slide 4:(1) Based on 2015 WTI oil pricing of US$58/bbl; AECO gas $3.50/gj and a CAD/USD exchange rate of $0.83. Slide 6:(1) December 31, 2013 reserves. Slide 7:(1) Assumes CAD/USD exchange rate of $0.83 for 2015 and Sproule January 2015 price forecast for 2016 and after. (2) Assumes 10% capital savings due to reduction in service costs Slide 9: (1) WTI oil pricing of US$58/bbl; AECO gas $3.50/gj; CAD/USD exchange rate of $0.83 was assumed for 2015. Sproule January 2015 price forecast was used for 2016 and after. Slide 13 - 15: (1) WTI oil pricing of US$58/bbl; AECO gas $3.50/gj; CAD/USD exchange rate of $0.83 was assumed for 2015. Sproule January 2015 price forecast was used for 2016 and after. Slide 18:(1) Based on Sproule's December 31, 2014 Revised Price Forecast 23

24 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. Contingent resources are those quantities of oil estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters, or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. All contingent resources represented in this document are considered Economic Contingent Resources based on the McDaniel & Associates Consultants Ltd. January 1 Price Forecast and an economic hurdle rate of the before tax net present value at a discount rate of 10% being greater than 0 (i.e. ROR >= 10%). The primary contingency which prevents the classification of Surge's contingent resources as reserves is capital budgeting restraints that allow the resources to be developed within a reasonable time frame. This time frame can be defined as 3 – 4 years. As additional drilling and/or development takes place, it is expected that some or all of the contingent resources will be booked as reserves. 24

25 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, legal settlement expenses, decommissioning expenditures, cash settled stock-based compensation, transaction costs and current tax on disposition. 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. 25


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