Corporate Presentation June 2017

Transcription

1 YGR Corporate Presentation June 2017

2 Corporate Snapshot Ticker Shares Outstanding (mm) Capitalization Reserves and Locations (2) Basic 80.2 Options (weighted avg. price $1.55) 7.7 Fully Diluted 87.9 Market Cap ($mm) (at $3.27 / share) (1) $287 December 31, 2016 mmboe NPV10 ($mm) NAV (3) / FD Share Recycle Ratio (4) Proved Developed 7.9 $139.1 $ x Total Proved 36.5 $489.6 $ x Proved + Probable 60.6 $734.5 $ x Based on 1-mile Gross Net Implied Value Provided / Location (5) Booked Cardium Locations $1.4mm Q Net Debt ($mm) $78 ($100mm credit facility with ATB) Enterprise Value ($mm) $365 Insider Ownership Total Cardium Locations $0.4mm 2) Reserves effective as at December 31, 2016 based on the reserve report prepared by Deloitte LLP, independent petroleum engineers (the Reserves Report ) 3) NAV = NPV10 Reserve Value less Net Debt and excludes undeveloped land value 4) As at December 31, ) Net Value per Location calculated as (Current Enterprise Value - PDP Reserves value at December 31, 2016) / Total and Booked net locations, respectively Basic 14% Fully Diluted 21% 1) Price as at June 9, 2017 Highly motivated management and board with insiders owning 14% of the basic shares and 21% of the fully diluted shares Majority of reserves bookings based on old well path; last well program helped de-risk / delineate the acreage Probabilistic risk vs. reserves risk now 2

3 The Team Management Team Jim Evaskevich, President & CEO 30+ years extensive executive experience with strong operations background Lorne Simpson B.Sc., C.E.T., VP, Operations 30+ years experience in the industry Supervisor, Drilling Ops with PetroBakken Energy Ltd. Engineered, drilled or completed 250 HZ Cardium wells, 200 HZ Bakken wells, 2 HZ Duvernay wells, 25 HZ Montney wells, and dozens of Blue Sky, Viking, SWS, Glauc, and Rock Creek HZ wells Board of Directors Gordon Bowerman Chairman President of Cove Resources Ltd Founder of several successful private and public oil and gas companies Robert Weir President of Weir Resource Management Ltd Jim Evaskevich President and CEO of Yangarra Resources Ltd Randall Faminow, VP, Land 30+ years of experience in all aspects of oil and gas land work, including negotiation, acquisitions and divestments, contracts and mergers James Glessing, CA, CFO 17+ years oil and gas accounting experience Executive and financial experience as CFO with North Peace Energy Corp Controller at BlackRock Ventures, Canadian Natural Resources, Shell and Deloitte Neil Mackenzie Director of various public companies, including Canyon Technical Services Currently a partner in Blackstone Fluids, an oil and gas drilling fluids company Ted Morton A former Canadian politician and cabinet minister in the Alberta government Has held various positions in the Alberta Government including Minister of Energy ( ), Minister of Finance and Enterprise ( ), and Minster of Sustainable Resources ( ) 3

4 Why Own Yangarra? Top Decile Full Cycle rates of return Central Alberta Cardium formation focus Low-cost operator, high netbacks Q Cash costs totaled $13.08/boe Operating costs (including transportation) of $7.93/boe Royalties of $3.05/boe (8% of revenue) G&A costs of $0.51/boe Finance and interest costs of $1.59/boe Breakeven pricing, including reserve replacement of $22.49/boe Operating margins were 72% and cash flow margins were 67% 2016 F&D costs of $9.41/boe Low-cost philosophy, not just a result of current low commodity prices Consistent, low risk Cardium economics Last 10-well program proves new method of drilling New path currently not fully captured in reserve report Potential Duvernay upside 4

5 Cardium Formation119 (89 net) Sections of Cardium #7 - YGR 102/ W5 2.0 mile 102 stages 1,533 tons On Prod: March 23, 2017 IP35 Rate: 662 boe/d (~38% liquids) #9 - YGR 100/ W5 2.0 mile 109 stages 1,640 tons On Prod: March 1, 2017 Clean-up phase (Day 1-50): 130 boe/d (98% liquids) Production phase (Day 51-65): 173 boe/d (94% liquids) #5 - YGR 100/ W5 2.0 mile 103 stages 1,114 tons On Prod: February 2, 2017 IP35 Rate: 645 boe/d (89% liquids) #8 - YGR 100/ W5 2.0 mile 105 stage 1,535 tons On Prod: April 6, 2017 IP27 Rate: 1,017 boe/d (~80% liquids) #10 - YGR 100/ W5 2.0 mile 104 stages 1,565 tons On Prod: April 6, 2017 IP37 Rate: 313 boe/d (~69% liquids) #6 - YGR 102/ W5 2.0 mile 107 stages 1,571 tons On Prod: February 3, 2017 Clean-up phase (Day 1-20): 217 boe/d (93% liquids) Production phase (Day 21-35): 534 boe/d (88% liquids) #2 - YGR 100/ W5 2.0 mile 74 stages 1,120 tons On Prod: October 25, 2016 IP90 Rate: 120 boe/d (94% liquids) #3 - YGR 104/ W5 1.4 mile 69 Stages 1,056 tons On Prod: October 29, 2016 IP90 Rate: 414 boe/d (77% liquids) #1 - YGR 103/ W5 1.6 mile 71 Stages 1,070 tons On Prod: October 5, 2016 IP90 Rate: 480 boe/d (82% liquids) #4 - YGR 100/ W5 2.0 Mile 101 Stages 1,520 tons On Prod: December 5, 2016 IP30: 395 boe/d (76% liquids) Well #2 drilled using old well path Well #7 restricted due to capacity constraints Well #9 on pump, recently started flowing 5

6 Full Cycle Returns 1. Half cycle IRR is based on actual drilling and completion costs, production to date and P+P reserves 2. Full cycle IRR allocates all other capital costs to the wells (i.e. land, G&G, infrastructure) 6

7 Reserves (mmboe) 2P Reserves / share Reserves Growth Reserves Per Share (boe per share) (2P) Reserves Profile $0.80 $0.70 $0.60 $0.50 $0.40 $0.30 $0.20 $0.10 $0.22 $0.31 $0.36 $0.65 $0.60 $0.76 Nat. Gas 53% Volumes (boe) Oil/ NGL's 47% NPV10 ($) Nat. Gas 18% Oil/ NGL's 82% $ Gross Reserves (mmboe) P Reserves 2P Reserves 7

8 Finding & Development Costs* ($ / boe) 2P Reserve Additions (mmboe) Recycle Ratio* (x) WTI ($US) / bbl F&D and Recycle Ratios Finding and Development Recycle Ratio vs Added Reserve Volumes $ x $140 $ x $120 $ x $100 $ x 3x $80 $60 $ x $40 $5 5 1x $20 $ x $0 1P F&D / boe 2P F&D / boe 2P Net Reserve Adds 1P Recycle Ratio 2P Recycle Ratio WTI (USD) / bbl *Includes changes in future capital NPV10 BT 2P 33% PDP 19% PUD 48% 2P NPV10: $734.5 million Reserves (1) PROB 39% 1. Reserves effective as at December 31, 2016 based on the Reserves Report Volumes PDP 13% PUD 48% 2P Reserves: 60.6 mmboe *Excludes realized gains and losses on hedging Consistent improvement in, and continued focus on, F&D costs and recycle ratios Management estimates proven and probable Cardium locations have a similar chance of success Reserve Life Index ( RLI ) 37 years with one rig 18 years with two rigs 12 years with three rigs 8

9 Production (boe/d) Production / MM Shares Net Debt / Trailing Cash Flow Production (boe/d) # of Producing Wells Production Growth Production Per Share Production Vintage x 5x 4x 9,000 8,000 7,000 6, based on 5 wells drilled in the first quarter and 12 wells in second half of x 5, x 4,000 3, x 2, x Q Prod. Per MM Shares Net Debt / Cash Flow Note: Production volumes include royalty barrels Gross Production (boe/d) 5,000 4,000 3,000 2,000 1, Q , # of Wells 2015 to 2016 capital spent on efficiency and improving IPs and recovery (ball drop to sliding sleeve) But capital allocation focused on growing inventory / land base throughout the Cardium Halo at attractive prices Q production of 4,483 boe/d (59% liquids) 2017 onwards focusing on significant production growth while continuing to grow land base Oil (bbl/d) NGLs (bbl/d) Gas (boe/d) Note: Production volumes include royalty barrels 9

10 Deeper Drill Path Upper Cardium Bioturbated Lower Cardium New Well Path Old Well Path Upper Cardium Bioturbated Zone Lower Cardium Old Frac Plane Upper Cardium (5-15% Porosity) Bioturbated Zone (20-80% Sand) New Frac Plane m m Lower Cardium (3-6% Porosity) m 10

11 Deeper Drill Path 105 API 3% Upper Reservoir Core analysis Porosity 9-11% Kmax average 0.09md OOIP 2,959 Mstb OBOEIP 8,218 Mbbl 10m Bioturbated Interval not analyzed Log Porosity 3-4% OOIP 2,198 Mstb OBOEIP 6,105 Mbbl Total Package OOIP/section 5,157 Mstb OBOEIP/section 14,323 Mbbl 11

12 Locations Cardium Drilling Inventory (1) Drilling Locations (1-mile laterals) Net Gross 752 gross (522 net) future 1-mile Cardium future drilling locations (1) Continued to grow inventory by strategically picking up land in the down turn Opportunity to drill extended reach wells 1) Management estimate is based on an estimate prepared by a non-independent qualified reserves evaluator of the Company in accordance with National Instrument and the COGE Handbook. 12

13 Production Per Day Cardium Well Economics Total (boe/d) Oil (bbls/d) Top 'Cardium Oil' Monthly Volumes Seen in April 2017 Monthly Associated Mth Daily Frac Company Field Vol Gas Oil Stage (bbl) (mmcf) (bbl/d) (#) Yangarra Resources Ferrier 17, na Company A Pembina 15, na Yangarra Resources Ferrier 14, Company B Willesden Green 12, na Company C Wapiti 11, na Company C Wapiti 10, Company C Ferrier 8, Company C Wapiti 8, Company C Ferrier 8, Lateral Length Months 2.0 Mile DCET ($mm) $3.75 IP30 - Oil (bbl/d) 390 IP30 - BOE (boe/d) 490 IP90 Oil (bbl/d) 295 IP90 - BOE (boe/d) 425 IP365 - BOE (boe/d) 335 Capital Eff (1 st Year Prod) ($/boe/d) 11,194 EUR (mboe) 474 F&D (Half Cycle) ($/boe) $7.91 Price Sensitivity: WTI (USD/bbl) $30.00 $40.00 $50.00 $60.00 IRR (%) 37% 84% 148% 231% NPV10% (BT) ($mm) $1.7 $3.9 $6.0 $8.0 Payback (years) Recycle Ratio (x) 2.3x 3.2x 4.1x 4.9x Completed the 10 well capital program that commenced in August of 2016 with all wells onstream as of April 2017 Halo Cardium is a proven success with new well path and new technology Not vertically exploited compared to main Cardium fields No plumbing required between wells Large untapped recoverable resource with the use of longer wells, drilling into deeper bioturbated zone and more frac ports $2.75/GJ natural gas; Exchange 0.76 USD/CAD; Ed Par Diff to WTI C$3.00/bbl Fixed operating costs of $5,000/month and variable operating costs of $5.00/boe plus transportation of ~$1.30/boe 13

14 2017 Capital Plan CAPEX budget for 2017 $70.0 million Budget focused on Cardium Wells 5 wells in the first quarter and 12 wells in the second half Funded with cash flow and the existing credit facilities 2017 Guidance Production (boe/d) Annual Average Cash flow from operations Year end net debt Annual debt to cash flow 5,500 6,000 boe/d $ million $ million : 1 Pricing Assumptions (annual average) WTI (USD/bbl) $47.50 Edmonton Par (CDN/bbl) $61.65 AECO (CDN/GJ) $

15 Duvernay Formation Recent Well Results (Sorted By RR Date) #1 Shell: 100/ W5 RR: 2014/02/17 35,097 bbl cum CND 339,544 mcf cum gas Completion: 14 stages; 70-90t #2 Shell: 103/ W5 RR: 2014/07/18 12,722 bbl cum cnd 781,274 mcf cum gas Completion: 16 stages; 72-90t 5 #3 YGR: 100/ W5 RR: 2014/09/04 10,726 bbl cum oil 132,267 mcf cum gas Completion: 81 stages #4 Inplay: 100/ W5 RR: 2015/01/27 40,337 bbl cum oil 112,199 mcf cum gas Completion: 9 stages; 240t #5 Shell: 100/ W5 RR: 2015/06/20 87,596 bbl cum cnd 884,479 mcf cum gas Completion: 29 stages; 72-90t 7 #6 Repsol: 100/ W5 RR: 2015/06/21 1,019 bbl cum oil 403,950 mcf cum gas Completion: 14 stages; 70-80t Source: GeoScout and Frac Database #7 Repsol: 102/ W5 RR: 2016/02/27 On: 2016/08/ bbl cum CND 269,639 mcf cum gas Completion: 22 stages; 180t YGR: W5 (1.5 Mile) IP boe/d 52% liquids (81 stages & 1,744 tons of sand) 15

16 Risk Management Program Oil Hedges bbl/d collar C$65.00 WTI/bbl and a ceiling of C$75.00 WTI/bbl (2017) 100 bbl/d at C$70.00 WTI/bbl (2017) 200 bbl/d at C$71.00 WTI/bbl (Feb Jun 2017) 200 bbl/d at C$69.25 WTI/bbl (Mar Jul 2017) 300 bbl/d at C$67.00 WTI/bbl (Apr Jun 2017) 500 bbl/d at C$75.20 WTI/bbl (Jul Dec 2017) 200 bbl/d at C$76.50 WTI/bbl (Jul Dec 2017) 2018 Sold Call on 200 bbl/d at US$70.00 WTI/bbl (2018) 2019 Sold Call on 500 bbl/d at US$60.00 WTI/bbl (2019) Sold Call on 200 bbl/d at US$65.00 WTI/bbl (2019) Differential Hedges bbl/d Edmonton par to WTI differential at US$2.85/bbl (Apr Dec 2017) Natural Gas ,000 GJ/d at $3.12/GJ (2017) 2,000 GJ/d at $3.01/GJ (2017) Interest Rate Swaps 4.400% (2.150% % Stamping Fee) Fixed rate on $10 million (June 2014-May 2018) 4.600% (2.350% % Stamping Fee) Fixed rate on $10 million (June 2014-June 2018) 4.185% (1.935% % Stamping Fee) Fixed rate on $10 million (May 2018-Nov 2023) 4.195% (1.945% % Stamping Fee) Fixed rate on $10 million (June 2018-Nov 2023) 16

17 Analyst Coverage Acumen Capital Finance Partners Limited Trevor Reynolds Oil and Gas Research Analyst (403) AltaCorp Capital Inc. Thomas Matthews, P.Eng, CFA Analyst - Institutional Research tmatthews@altacorpcapital.com (403) Canaccord Genuity Sam Roach, CFA Associate Analyst sroach@canaccordgenuity.com (403) Clarus Securities Inc. Robert Pare, CA, CFA Managing Director, Equity Research rpare@clarussecurities.com (403) Industrial Alliance Securities Inc. Michael Charlton Research Analyst - Oil & Gas mcharlton@mgisecurities.com (403) Paradigm Capital Inc. Ken Lin, CFA Oil and Gas Analyst kenl@paradigmcap.com (403) PI Financial Corp. Brian Purdy, P.Eng, MBA, CFA Research Analyst - Energy bpurdy@pifinancial.com (403) Raymond James Ltd. Jeremy McCrea, CFA Oil and Gas Analyst jeremy.mccrea@raymondjames.ca (403)

18 Forward Looking Statements Statements in this presentation may contain forward-looking information including expectations of future production and components of cash flow and earnings. Forward looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by the Company and described in the forward looking statements or information. These risks and uncertainties which may cause actual results to differ materially from the forward looking statements or information include, among other things: general economic and business conditions; the risk of instability affecting the jurisdictions in which the Company operates; the risks of the oil and natural gas industry, such as operational risks in exploring for, developing and producing crude oil and natural gas and market demand; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; risks and uncertainties involving geology of oil and natural gas deposits; the uncertainty of reserves estimates and reserves life; the ability of the Company to add production and reserves through acquisition, development and exploration activities; the Company s ability to enter into or renew leases; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of estimates and projections relating to production (including decline rates), costs and expenses; fluctuations in oil and natural gas prices, foreign currency exchange rates and interest rates; risks inherent in the Company s marketing operations, including credit risk; health, safety and environmental risks; and uncertainties as to the availability and cost of financing. Readers are cautioned that the foregoing list is not exhaustive of all possible risks and uncertainties. The reader is cautioned not to place undue reliance on this forward-looking information. The forward looking statements or information contained in this presentation are made as of the date hereof and the Company 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 required by applicable securities laws. The forward looking statements or information contained in this presentation are expressly qualified by this cautionary statement. 18

19 Reserve Definitions Natural gas has been converted to a barrel of oil equivalent (Boe) using 6,000 cubic feet (6 Mcf) of natural gas equal to one barrel of oil (6:1), unless otherwise stated. The Boe conversion ratio of 6 Mcf to 1 Bbl is based on an energy equivalency conversion method and does not represent a value equivalency; therefore Boe's may be misleading if used in isolation. References to natural gas liquids ("NGLs") in this news release include condensate, propane, butane and ethane and one barrel of NGLs is considered to be equivalent to one barrel of crude oil equivalent (Boe). One ("BCF") equals one billion cubic feet of natural gas. One ("Mmcf") equals one million cubic feet of natural gas. Reserve Definitions: (a) "Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. (b) "Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. (c) "Developed" reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production. (d) "Developed Producing" reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty. (e) "Developed Non-Producing" reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown. (f) "Undeveloped" reserves are those reserves expected to be recovered from know accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned. (g) The Net Present Value (NPV) is based on Deloitte AJM Forecast Pricing and costs. The estimated NPV does not necessarily represent the fair market value of our reserves. There is no assurance that forecast prices and costs assumed in the Deloitte AJM evaluations will be attained, and variances could be material. This presentation contains references to measures used in the oil and natural gas industry such as netback. These measures do not have standardized meanings prescribed by GAAP and therefore should not be considered in isolation. These reported amounts and their underlying calculations are not necessarily comparable or calculated in an identical manner to a similarly titled measure of other companies where similar terminology is used. Where these measures are used they should be given careful consideration by the reader. These measures have been described and presented in this presentation in order to provide shareholders and potential investors with additional information regarding the Corporation's liquidity and its ability to generate funds to finance its operations. Netback denotes petroleum and natural gas revenue and realized gains or losses on financial instruments less royalty expenses, operating expenses and transportation and marketing expenses calculated on a per boe basis. 19

20 Yangarra Resources Ltd. 1530, Ave. SW Calgary, Alberta T2P 2X