Corporate Presentation May 2017 TSX: YGR TSX: YGR Corporate - - PowerPoint PPT Presentation

TSX: YGR TSX: YGR

Corporate Presentation May 2017

TSX: YGR 2

Corporate Snapshot

1) Price as at May 10, 2017

Capitalization Reserves and Locations (2)

Ticker TSX: YGR Shares Outstanding (mm) Basic 80.6 Options (weighted avg. price $1.50) 7.8 Fully Diluted 88.4 Market Cap ($mm) (at $2.90 / share)(1) $234 2017 Q1 Net Debt ($mm) $78 ($100mm credit facility) Enterprise Value ($mm) $312 Insider Ownership Basic 13% Fully Diluted 21%

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

• Highly motivated management and board with insiders owning 13% of the basic shares and 21% of

the fully diluted shares December 31, 2016 mmboe NPV10 ($mm) Proved Developed 7.9 $139.1 Total Proved 36.5 $489.6 2P 60.6 $734.5 Total Cardium Locations (1-mile) 752 Gross (522 Net) Booked Cardium Locations (1-mile) 214 Gross (150 Net)

NAV(3) / Fully Diluted Share (Excl. land) December 31, 2016 Proved Developed (2.1 recycle ratio) $0.96 Total Proved (2.9 recycle ratio) $5.01 Total Proved + Probable (3.2 recycle ratio) $7.84

TSX: YGR 3

Jim Evaskevich, President & CEO

• 30+ years extensive executive experience with strong
• perations 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

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

Board of Directors Management Team

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

included Minister of Energy (2011-2012), Minister of Finance and Enterprise (2010-2011), and Minster of Sustainable Resources (2006-2010)

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

People

TSX: YGR 4

Why Own Yangarra?

• Top Decile Full Cycle rates of return
• Low-cost operator, high netbacks
• 2017 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
• Operating margins were 72% and cash flow margins were 67%.
• Finding & Development costs of $6.18/boe
• Low-cost philosophy, not just a result of current low commodity prices
• Central Alberta Cardium formation focus
• Large future drilling inventory
• Consistent, low risk Cardium economics
• Potential Duvernay upside

TSX: YGR 5

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)

• Capital allocation is determined based on narrowing the gap between half

cycle and full cycle returns

TSX: YGR 6

Cardium Drilling Inventory (1)

• 752 gross (522 net) future 1-mile Cardium future drilling locations (1)
• 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 51-101 and the COGE Handbook, with an effective date of October 15, 2015.

Drilling Locations (1-mile laterals) Proportionate (gross locations)

#4 - YGR 100/1-26-37-8W5 – 2.0 Mile 101 Stages – 1,520 tons On Prod: December 5, 2017 IP30: 395 boe/d (76% liquids) #3 - YGR 104/14-19-41-5W5 – 1.4 mile 69 Stages – 1,056 tons On Prod: October 29, 2016 IP90 Rate: 414 boe/d (77% liquids) #2 - YGR 100/1-14-41-6W5 – 2.0 mile 74 stages 1,120 tons On Prod: October 25, 2016 IP90 Rate: 120 boe/d (94% liquids) #5 - YGR 100/2-26-39-9W5 – 2.0 mile 103 stages – 1,114 tons On Prod: February 2, 2017 IP35 Rate: 645 boe/d (89% liquids) #1 - YGR 103/4-7-41-5W5 – 1.6 mile 71 Stages – 1,070 tons On Prod: October 5, 2016 IP90 Rate: 480 boe/d (82% liquids) #6 - YGR 102/8-14-41-6W5 – 2.0 mile 101 stages – 1,520 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) #10 - YGR 100/3-23-37-8W5 – 2.0 mile 104 stages – 1,565 tons On Prod: April 6, 2017 IP37 Rate: 313 boe/d (~69% liquids) #8 - YGR 100/1-34-39-8W5 – 2.0 mile 105 stage – 1,535 tons On Prod: April 6, 2017 IP27 Rate: 1,017 boe/d (~80% liquids) #9 - YGR 100/5-19-41-7W5 – 2.0 mile 109 stages – 1,640 tons On Prod: March 1, 2017 Clean-up phase (Day 1-20): 130 boe/d (98% liquids) Production phase (Day 21-35): 173 boe/d (94% liquids) #7 - YGR 102/16-15-44-10W5 – 2.0 mile 102 stages – 1,533 tons On Prod: March 23, 2017 IP35 Rate: 662 boe/d (~38% liquids) Well #2 drilled using old well path Well #7 restricted due to capacity constraints Well #9 on pump, recently started flowing

Cardium Formation

119 (89 net) Sections of Cardium 7

Upper Cardium (5-15% Porosity) Lower Cardium (3-6% Porosity) Bioturbated Zone (20-80% Sand) 2.5-4.0m 1.5-3.0m 3.0-7.0m Old Well Path New Well Path Old Frac Plane New Frac Plane

Upper Cardium Lower Cardium Bioturbated Zone

Upper Cardium Bioturbated Lower Cardium

Deeper Drill Path

8

Upper Reservoir

Core analysis Porosity 9-11% Kmax average 0.09md

Bioturbated

Interval not analyzed Log Porosity 3-4% 3%

OOIP 2,959 Mstb OBOEIP 8,218 Mbbl OOIP 2,198 Mstb OBOEIP 6,105 Mbbl

10m

OOIP/section 5,157 Mstb OBOEIP/section 14,323 Mbbl

105 API

9

Deeper Drill Path

TSX: YGR 10

2017 Capital Plan

CAPEX budget for 2017 $50.0 million Budget focused on Cardium Wells

• 5 wells in the first quarter and 10 wells in the second half

Funded with cash flow and the existing credit facilities 2017 Guidance Production (boe/d) Annual Average 4,500 – 5,000 boe/d Cash flow from operations $45 – 50 million Year end net debt Annual debt to cash flow $65 – 70 million 1.3 – 1.6 : 1 Pricing Assumptions (annual average) WTI (USD/bbl) $55.00 Edmonton Par (CDN/bbl) $68.71 AECO (CDN/GJ) $3.00

TSX: YGR 11

2016 F&D and Recycle Ratios

• Consistent improvement in, and

continued focus on, F&D costs and recycle ratios

• In Yangarra’s view Probable and

proven 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

Finding and Development Recycle Ratios NPV10 BT Volumes Reserves (1)

2P Reserves: 60.6 mmboe 2P NPV10: $734.5 million

1) Reserves effective as at December 31, 2016 based on the Reserves Report

TSX: YGR 12

Duvernay Formation

15-19-39-6W5 (1.5 Mile) IP 20 - 700 boe/d 52% liquids (81 stages & 1,744 tons of sand)

TSX: YGR 13

Risk Management Program

Oil Hedges 2017 200 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 2017 500 bbl/d Edmonton par to WTI differential at US$2.85/bbl (Apr – Dec 2017) Natural Gas 2017 2,000 GJ/d at $3.12/GJ (2017) 2,000 GJ/d at $3.01/GJ (2017) Interest Rate Swaps 4.400% (2.150% + 2.25% Stamping Fee) Fixed rate on $10 million (June 2014-May 2018) 4.600% (2.350% + 2.25% Stamping Fee) Fixed rate on $10 million (June 2014-June 2018) 4.185% (1.935% + 2.25% Stamping Fee) Fixed rate on $10 million (May 2018-Nov 2023) 4.195% (1.945% + 2.25% Stamping Fee) Fixed rate on $10 million (June 2018-Nov 2023)

TSX: YGR 14

Analyst Coverage

Acumen Capital Finance Partners Limited Trevor Reynolds Oil and Gas Research Analyst treynolds@acumencapital.com (403) 410-6842 AltaCorp Capital Inc. Thomas Matthews, P.Eng, CFA Analyst - Institutional Research tmatthews@altacorpcapital.com (403) 539-8621 Canaccord Genuity Sam Roach, CFA Associate Analyst sroach@canaccordgenuity.com (403) 691-7809 Clarus Securities Inc. Robert Pare, CA, CFA Managing Director, Equity Research rpare@clarussecurities.com (403) 767-0821 Industrial Alliance Securities Inc. Michael Charlton Research Analyst - Oil & Gas mcharlton@mgisecurities.com (403) 705-4978 Paradigm Capital Inc. Ken Lin, CFA Oil and Gas Analyst kenl@paradigmcap.com (403) 513-1042 PI Financial Corp. Brian Purdy, P.Eng, MBA, CFA Research Analyst - Energy bpurdy@pifinancial.com (403) 543-2823 Raymond James Ltd. Jeremy McCrea, CFA Oil and Gas Analyst jeremy.mccrea@raymondjames.ca (403) 509-0518

TSX: YGR 15

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

• il 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

• r information contained in this presentation are expressly qualified by this cautionary statement.

Forward-looking Statements

16 TSX: YGR

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

• therwise 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.

Reserve Definitions

17 TSX: YGR

Yangarra Resources Ltd. 1530, 715 – 5 Ave. SW Calgary, Alberta T2P 2X6 403-262-9558