Corporate Presentation May 2018

Transcription

1 YGR Corporate Presentation May 2018

2 Corporate Snapshot Ticker Shares Outstanding (mm) Capitalization Reserves and Locations (2) Basic 85.3 Options (weighted avg. price $3.66) 7.8 Fully Diluted 93.1 December 31, 2017 mmboe NPV10 ($mm) NAV (3) / FD Share Recycle Ratio (4) Proved Developed 12.0 $204 $ x Total Proved 55.9 $722 $ x Proved + Probable 87.9 $1,027 $ x Market Cap ($mm) (at $6.35 / share) (1) $ 542 Q Net Debt ($mm) (unaudited) $ 108 ($150mm credit facility) Enterprise Value ($mm) $ 650 Insider Ownership Basic 13% Fully Diluted 21% Locations as at December 31, 2017 Based on 1-mile Gross Net Booked Cardium Locations Total Cardium Locations ) Reserves effective as at December 31, 2017 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, 2017) / Total and Booked net locations, respectively 1) Price as at May 7, 2018 Highly motivated management and board with insiders owning 13% 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 18+ 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 2018 First quarter cash costs totaled $14.06/boe Operating costs (including transportation) of $8.05/boe Royalties of $4.15/boe (9% of revenue) G&A costs of $0.57/boe Finance and interest costs of $1.29/boe Breakeven pricing, including reserve replacement of $23.24/boe Operating margins were 67% and cash flow margins were 63% 2017 F&D costs of $9.18/boe Low-cost philosophy, not just a result of current low commodity prices Consistent, low risk Cardium economics Potential Duvernay upside 4

5 IRR Full Cycle Returns 140% Half Cycle IRR (¹) Full Cycle IRR (²) 120% 100% 80% 60% 131% 105% 40% 79% 80% 86% 67% 65% 20% 0% 41% 34% 31% 33% 24% 26% 27% 31% 12% 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) 5

6 Locations Cardium Drilling Inventory (1) Drilling Locations (1-mile laterals) Net Gross 940 gross (740 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. 6

7 Cardium Formation 7

8 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 8

9 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 9

10 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) $40.00 $50.00 $60.00 $70.00 IRR (%) 84% 148% 231% 334% NPV10% (BT) ($mm) $3.9 $6.0 $8.0 $10.0 Payback (years) Recycle Ratio (x) 3.2x 4.1x 4.9x 5.7x 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 10

11 Production (boe/d) Production / MM Shares Net Debt / Trailing Cash Flow Production (boe/d) # of Producing Wells Production Growth ,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000 0 Production Per Share 6x 5x 4x 3x 2x 1x 0x Q Gross Production (boe/d) Q Oil (bbl/d) NGLs (bbl/d) Gas (boe/d) 14,000 12,000 10,000 8,000 6,000 4,000 2,000 Production Vintage # 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 7,500 boe/d 2018 onwards focusing on significant production growth while continuing to grow land base

12 Reserves (mmboe) 2P Reserves / share Reserves Growth Reserves Per Share (boe per share) (2P) Reserves Profile Volumes (boe) NPV10 ($) Nat. Gas 53% Oil/ NGL's 47% Nat. Gas 9% Oil/ NGL s 91% Gross Reserves (mmboe) P Reserves 2P Reserves 12

13 Finding & Development Costs* ($ / boe) 2P Reserve Additions (mmboe) Recycle Ratio* (x) F&D and Recycle Ratios Finding and Development Recycle Ratio $ x $ x $ x $ x 3x $ x $5 5 1x $ P F&D / boe 2P F&D / boe 2P Net Reserve Adds *Includes changes in future capital NPV10 BT PROB 30% PDP 20% PUD 50% 2P NPV10: $1.03 billion Reserves (1) PROB 36% 1. Reserves effective as at December 31, 2017 based on the Reserves Report Volumes PDP 14% PUD 50% 2P Reserves: 87.9 mmboe 0x 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 (2P) ( RLI ) 32 years 1P Recycle Ratio *Excludes realized gains and losses on hedging Future Development Capital (2P) $552.5 million 2P Recycle Ratio 13

14 2018 Capital Plan CAPEX budget for wells in the second half Budget focused on Cardium Wells Funded with cash flow and the existing credit facilities 2018 Guidance Production (boe/d) Annual Average Cash flow from operations Year end net debt Annual debt to cash flow $90.0 million 9,000 10,000 boe/d $80 90 million $ million : 1 Pricing Assumptions (annual average) WTI (USD/bbl) $55.00 Edmonton Par (CDN/bbl) $63.75 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 Paramount: 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$62.50 WTI/bbl and a ceiling of C$75.90 WTI/bbl (2018) 300 bbl/d collar C$62.50 WTI/bbl and a ceiling of C$76.10 WTI/bbl (Jan Jun 2018) 300 bbl/d collar US$55.00 WTI/bbl and a ceiling of US$64.40 WTI/bbl (Jul Dec 2018) 300 bbl/d at C$71.60 WTI/bbl (2018) 300 bbl/d at C$75.17 WTI/bbl (Jan Jun 2018) 300 bbl/d at US$49.10 WTI/bbl (Jan Jun 2018) 300 bbl/d at US$52.15 WTI/bbl (Jan Jun 2018) 300 bbl/d at US$56.75 WTI/bbl (Jan Jun 2018) 300 bbl/d at US$61.00 WTI/bbl (Feb Jun 2018) 600 bbl/d at C$75.40 WTI/bbl (Jul Dec 2018) C$74.28/bbl 300 bbl/d at C$76.00 WTI/bbl (Jul Dec 2018) 300 bbl/d at C$78.20 WTI/bbl (Mar Dec 2018) 300 bbl/d at C$80.15 WTI/bbl (Apr Dec 2018) 300 bbl/d at C$81.05 WTI/bbl (Jul Dec 2018) Sold Call on 300 bbl/d at C$75.17 WTI/bbl (Jul Dec 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) Propane bbl/d at US$32.34/bbl (2018) H H ,900 bbl/d 2,600 bbl/d C$76.70/bbl 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) CIBC World Markets Scott Reid, CFA Institutional Equity Research scott.reid@cibc.com (403) Cormark Securities Inc. Amir Arif, CFA E&P Equity Research aarif@cormark.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) Raymond James Ltd. Jeremy McCrea, CFA Oil and Gas Analyst jeremy.mccrea@raymondjames.ca (403)

18 Forward Looking Statements This presentation contains a summary of management's assessment of results and should be read in conjunction with the Consolidated Financial Statements and related Management's Discussion and Analysis for the quarter ended March 31, 2018, as filed on the SEDAR profile of Yangarra Resources Ltd. (the "Company"). This presentation contains certain forward-looking statements, which include assumptions with respect to (i) drilling success; (ii) commodity prices; (iii) production; (iv) reserves; (v) future capital expenditures; (vi) future operating costs; (vii) cash flow; and (viii) potential markets for the Company's production. The reader is cautioned that assumptions used in the preparation of such information may prove to be incorrect. Certain information regarding the Company set forth in this presentation, including statements regarding management's assessment of the Company's future plans and operations, the planning and development of certain prospects, the 2018 Capital Program and the Company's proposed exploration and development activities and the timing thereof, including the amount and allocation of capital expenditures, the number and types of wells to be drilled and brought on production and the timing thereof, estimates of total and net capital expenditures, and the focus of, the objectives of and the anticipated results from the 2018 Capital Program, production estimates, reserve estimates, productive capacity and economics of new wells, undeveloped land holdings and values, capital expenditures and the timing and allocation thereof (including the number, location and costs of planned wells), the total future capital required to bring undeveloped proved and probable reserves onto production, and expected production growth, may constitute forward-looking statements under applicable securities laws and necessarily involve substantial known and unknown risks and uncertainties. With respect to the Company's 2018 production guidance, the key assumptions are that: the 2018 Capital Program will be carried out as currently contemplated; no unexpected outages occur in the infrastructure that the Company relies on to produce its wells and that any transportation service curtailments or unplanned outages that occur will be short in duration or otherwise insignificant; existing wells continue to meet production expectations; and future wells scheduled to come on production meet timing, production and capital expenditure expectations. These forward-looking statements are subject to numerous risks and uncertainties, certain of which are beyond the Company's control, including without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, failure of foreign markets to become accessible, the impact of general economic conditions, industry conditions, volatility of commodity prices, currency fluctuations, environmental risks, competition, the lack of availability of qualified personnel or management, inability to obtain drilling rigs or other services, capital expenditure costs, including drilling, completion and facility costs, unexpected decline rates in wells, wells not performing as expected, stock market volatility, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources, the impact of general economic conditions in Canada, the United States and overseas, industry conditions, changes in laws and regulations (including the adoption of new environmental laws and regulations) and changes in how they are interpreted and enforced, increased competition, fluctuations in foreign exchange or interest rates and market valuations of companies with respect to announced transactions and the final valuations thereof. Readers are cautioned that the foregoing list of factors is not exhaustive. The Company's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits the Company will derive therefrom. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Additional information on these and other factors that could affect the Company's operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website ( or the Company's website ( including the Company's MD&A for the quarter March 31,

19 Forward Looking Statements (cont.) The forward-looking statements contained in this presentation are made as of the date on the front page and the Company assumes no obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws. Certain information contained herein is based on, or derived from, information provided by independent third-party sources. The Company believes that such information is accurate and that the sources from which it has been obtained are reliable. The Company cannot guarantee the accuracy of such information, however, and has not independently verified the assumptions on which such information is based. The Company does not assume any responsibility for the accuracy or completeness of such information. This presentation also contains future-oriented financial information and financial outlook information (collectively, "FOFI") about prospective results of operations, cash flow, capital expenditures, net debt and components thereof, all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth in the above paragraphs. FOFI contained in this presentation was made as of the date of this presentation and was provided for the purpose of providing information about management's current expectations and plans relating to the future, including with respect to the Company's ability to fund its expenditures. The Company disclaims any intention or obligation to update or revise any forward-looking statements or FOFI contained in this presentation, whether as a result of new information, future events or otherwise, unless required pursuant to applicable securities law. Readers are cautioned that the forward-looking statements and FOFI contained in this presentation should not be used for purposes other than for which it is disclosed herein. The forward-looking statements and FOFI contained in this presentation are expressly qualified by this cautionary statement. 19

20 Non-GAAP Measures This presentation contains references to measures used in the oil and natural gas industry such as netback, net debt and cash flow. These measures do not have standardized meanings prescribed by International Financial Reporting Standards ( IFRS ) 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 Company'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. Cash flow should not be considered an alternative to, or more meaningful than, cash provided by operating, investing and financing activities or net earnings as determined in accordance with IFRS, as an indicator of the Company's performance or liquidity. Cash flow is used by the Company to evaluate operating results and the Company's ability to generate cash flow to fund capital expenditures and repay debt. Included in this presentation are estimates of the Company's 2018 cash flow which are based on various assumptions as to production levels, commodity prices and other assumptions, are provided for illustration only and are based on budgets and forecasts that have not been finalized and are subject to a variety of contingencies including prior years' results. To the extent such estimates constitute a financial outlook, they were approved by management of the Company and are included to provide readers with an understanding of the Company's anticipated cash flow based on the capital expenditures and other assumptions described and readers are cautioned that the information may not be appropriate for other purposes. The Company uses net debt as a measure to assess its financial position. Net debt includes current liabilities (including the Company's credit facility and excluding the current portion of decommissioning obligations) less current assets (excluding property, plant and equipment, held for sale and risk management contracts). Analogous Information Certain information provided in this news release may constitute "analogous information" under applicable securities legislation, such as reserve and resource estimates or the reserves and resources present on the Company's lands, and nearby lands, total production and production-rates from wells drilled by the Company or other industry participants located in geographical proximity to lands held by the Company. This information is derived from publicly available information sources (as at the date of this news release) that the Company believes are predominantly independent in nature. The Company believes this information is relevant as it helps to define the reservoir characteristics in which the Company may have an interest. The Company is unable to confirm that the analogous information was prepared by a qualified reserves evaluator or auditor or in accordance with the Canadian Oil and Gas Evaluation Handbook and therefore, the reader is cautioned that the data relied upon by the Company may be in error, may not be analogous to the Company's land holdings and/or may not be representative of actual results of wells anticipated to be drilled or completed by the Company in the future. 20

21 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. 21