Corporate Presentation March 2016 TSX: YGR TSX: YGR Corporate - - PowerPoint PPT Presentation

TSX: YGR TSX: YGR

Corporate Presentation March 2016

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Corporate Snapshot

1) Price as at March 15, 2016

Capitalization Reserves and Locations (2)

Ticker TSX: YGR Shares Outstanding (mm) Basic 67.7 Options (weighted avg. price $1.83) 6.1 Fully Diluted 74.0 Market Cap ($mm) (at $0.67 / share)(1) $45 Q4 Net Debt ($mm) $61 ($80mm credit facility with ATB) Enterprise Value ($mm) $106 Insider Ownership Basic 14% Fully Diluted 21%

2) Reserves effective as at December 31, 2015 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 14% of the basic shares and 21% of

the fully diluted shares mmboe NPV10 ($mm) Proved Developed 5.6 $97.9 Total Proved 24.7 $315.9 2P 40.6 $499.5 Total Cardium Locations 462 Gross (270 Net) Booked Cardium Locations 140 Gross (87 Net)

NAV(3) / Share (Excl. land) Proved Developed $0.56 Total Proved $3.78 Total Proved + Probable $6.59

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• Establish Sustainability
• Target and maintain 2,750 – 3,000 boe/d and continue building deep inventory for

when commodity prices turn

• Prepare for future growth
• Acquire Cardium land at the low-end of the cycle
• Consolidate partner interests
• Secure infrastructure capacity
• Prepare and drill (one-well) pad-drilling sites; leaving significant torque to add 3

wells on existing pads

• Future growth opportunity
• Current inventory supports an ability to increase pace of development when

justified by full cycle returns

• Will ramp up to 2 or 3 rigs as commodity price improve
• Multi-well pads with one well now ready for a quick ramp-up to a 4-5 well pad

Corporate Strategy

Low commodity prices

• Build inventory, avoid eroding well

economics Recovering commodity prices

• Accelerate drilling and add lower-cost

production on half-cycle economics

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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

• 15+ 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

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Why Ow n Yangarra?

• Top Decile Full Cycle rates of return
• Low-cost operator, high netbacks
• 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

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24% 41% 67% 65% 33% 79% 12% 34% 26% 31% 27% 44%

31%

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 2010 2011 2012 2013 2014 2015 IRR

Half Cycle IRR ⁽¹⁾ Full Cycle IRR ⁽²⁾ Full Cycle with Duvernay

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

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PDP 14% 1P 47% 2P 39%

F& D and Recycle Ratios

0.0x 1.0x 2.0x 3.0x 4.0x 5.0x 6.0x 7.0x 2010 2011 2012 2013 2014 2015 Proven Recycle P+P Recycle $- $5.00 $10.00 $15.00 $20.00 $25.00 $30.00 $35.00 $40.00 2010 2011 2012 2013 2014 2015 $/boe Proven F&D P+P F&D

• 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

PDP 19% 1P 44% 2P 37%

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

2P Reserves: 40.6 mmboe 2P NPV10: $499.5 million

1) Reserves effective as at December 31, 2015 based on the Reserves Report

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Low -Cost Producer

• Company founded on a low cost operations

philosophy

• Consistent low cost mentality in high and low

commodity price environments

• We own and operate our facilities resulting

in lower operating costs (no hidden fees for financial engineering)

• Centralized field operations with Company
• wned equipment and experienced field staff
• Building our own separator packages
• 13 employees/contractors in head office; 6 field

employees/contractors

Low -Cost Driller

• Experienced drilling team
• Pad drilling from existing locations
• Long-term relationship with service providers
• Cemented liners and sliding sleeves reduce costs

significantly

• Coil fracs without nitrogen require less horsepower
• n location resulting in reduced completion costs

$0.00 $10.00 $20.00 $30.00 $40.00 $50.00 $60.00 Q1 2013 Q2 2013 Q3 2013 Q4 2013 Q1 2014 Q2 2014 Q3 2014 Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Realized Price⁽¹⁾

• Corp. Netback

Interest G&A Transportation

• Op. Costs

Royalties

Netback Analysis ($/boe) Cost per Meter Drilled vs. Drilling Cost per Well

1) Including derivative contracts and royalty income 691 524 474 486 369 $0 $1,000 $2,000 $3,000 $4,000 $5,000 $6,000 $7,000 $0 $100 $200 $300 $400 $500 $600 $700 $800 2011 2012 2013 2014 2015 Cost Per Well ($’000) Cost per Meter Drilled $ / Meter Drilled Drilling Cost per Well

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Updated Completion Technology

• Cemented liners and sliding sleeve
• Tighter well frac spacing
• Increased ability to target fracs
• Better frac isolation,
• No longer losing energy to packers
• Improved initial rates

Extended Reach Well Results

• Closable siding sleeve technology

has made extended reach wells possible

• Significant reduction in drilling costs

per meter with extended reach wells

5 10 15 20 25 30 2010 2011 2012 2013 2014 2015 $0 $50,000 $100,000 $150,000 $200,000 $250,000 Number Of Stages Cost per Stage Average number of stages per well Cost per stage 410 367 290 $0 $5,000 $10,000 $15,000 $20,000 $25,000 $30,000 $35,000 $40,000 $0 $50 $100 $150 $200 $250 $300 $350 $400 $450 1-Mile 1.5 Mile 2 Mile Cost per Frac Cost per Meter Drilled Drilling Cost per Meter Cost per Frac 18 Stages 30 Stages 45 Stages 100 200 300 400 500 600 700 800 900 1,000 KG of Sand/M3

Completion Stages and Costs Extended Reach Costs Sand Concentration

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2,832 2,134 1,563 1,808 1,578 1,807 1,376 1,134 1,187 970 473 373 273 298 173 $0 $1,000 $2,000 $3,000 $4,000 $5,000 $6,000 2011 2012 2013 2014 2015

Equip Complete Drill

Average 1-mile Well Costs ($M)

Cemented Completions Service Costs Reductions Monobore Drilling Extended Reach

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Cardium Formation

• Interest in 100+ sections
• 85+ horizontal wells drilled
• Secured firm capacity on gas

systems

• Increased firm capacity

from 0 in 2014 to 6.0 mmcf/d currently

Red Deer

80 km

Rocky Mountain House Yangarra Field Office

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Cardium Drilling Inventory (1)

• 462 gross (270 net) future 1-mile Cardium future drilling locations (1)
• Opportunity to drill extended reach wells
• Total Cardium gross oil in place of 559 mmboe (1)
• Willesden Green rock is generally tighter then Ferrier and North Willesden green

212 1-mile Locations 84 2-mile Locations 38 1.5-mile Locations 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)

50 100 150 200 250 300 350 400 450 500 2010 2011 2012 2013 2014 2015

Locations

Net Gross

78 Ferrier Locations 269 Willesden Green Locations 115 North Willesden Green Locations

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Risk Management Program

Oil Hedges 2016: 400 bbl/d costless collar C$73.45 WTI/bbl and a ceiling of C$85.00 WTI/bbl 2016: 400 bbl/d Edmonton par to WTI differential at US$3.95/bbl 2016: 200 bbl/d at C$54.00 WTI/bbl April – June 2016 Interest Rate Swaps 4.70% Fixed rate on $10 million (June 2014-June 2018) 4.85% Fixed rate on $10 million (June 2014-June 2018)

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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 Analyst - Institutional Research tmatthews@altacorpcapital.com (403) 539-8621 Clarus Securities Inc. Robert Pare, CA, CFA Managing Director, Equity Research rpare@clarussecurities.com (403) 767-0821 Dundee Capital Markets Brian Kristjansen Managing Director, Head of Energy Research bkristjansen@dundeecapitalmarkets.com (403) 509-2662 FirstEnergy Capital Corp. Michael Hearn, CA Research Analyst - Exploration & Production mjhearn@firstenergy.com (403) 444-8273 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 Raymond James Ltd. Jeremy McCrea, CFA Oil and Gas Analyst jeremy.mccrea@raymondjames.ca (403) 509-0518

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Appendix

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Glauconite Formation

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Duvernay South Block

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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.

Forw ard-looking Statements

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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

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